IR 05000254/2005002

IR 05000254-05-002, IR 05000265-05-002 on 01/01/2005-03/31/2005 for Quad Cities Nuclear Power Station, Units 1 & 2; Maintenance Risk Assessment and Emergent Work, Problem Identification and Resolution, and Other

ML051240300
Person / Time
Site:	Quad Cities
Issue date:	04/29/2005
From:	Ring M NRC/RGN-III/DRP/RPB1
To:	Crane C Exelon Generation Co, Exelon Nuclear
References
IR-05-002
Download: ML051240300 (46)

Text

ril 29, 2005

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000254/2005002; 05000265/2005002

Dear Mr. Crane:

On March 31, 2005, the U. S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Quad Cities Nuclear Power Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on April 5, 2005, with Mr. Tulon and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and to 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.

Based on the results of this inspection, the inspectors identified two issues of very low safety significance (Green). One of these issues was determined to involve a violation of NRC requirements. However, because this violation was of very low safety significance and because the issue was entered into the licensees corrective program, the NRC is treating this finding and issue as a Non-Cited Violation in accordance with Section V1.A.1 of the NRCs Enforcement Policy.

If you contest the subject or severity of a Non-Cited Violation, 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 Regulation Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Quad Cities Nuclear Power Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Mark A. Ring, Chief Branch 1 Division of Reactor Projects Docket Nos. 50-254; 50-265 License Nos. DPR-29; DPR-30

Enclosure:

Inspection Report 05000254/2005002; 05000265/2005002 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-254; 50-265 License Nos: DPR-29; DPR-30 Report No: 05000254/2005002; 05000265/2005002 Licensee: Exelon Nuclear Facility: Quad Cities Nuclear Power Station, Units 1 and 2 Location: 22712 206th Avenue North Cordova, IL 61242 Dates: January 1 through March 31, 2005 Inspectors: K. Stoedter, Senior Resident Inspector M. Kurth, Resident Inspector D. Chyu, Reactor Engineer B. Jose, Reactor Inspector P. Lougheed, Senior Engineering Inspector C. Phillips, Acting Senior Resident Inspector - Dresden T. Ploski, Senior Emergency Preparedness Analyst L. Ramadan, Nuclear Safety Professional G. Wilson, Senior Resident Inspector - Duane Arnold R. Ganser, Illinois Emergency Management Agency Approved by: M. Ring, Chief Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000254/2005002, 05000265/2005002; 01/01/2005-03/31/2005; Quad Cities Nuclear

Power Station, Units 1 & 2; Maintenance Risk Assessment and Emergent Work, Problem Identification and Resolution, and Other.

This report covers a 3-month period of baseline resident inspection and a regional inspection on emergency preparedness. The inspection was conducted by Region III inspectors and the resident inspectors. Two Green findings and one Non-Cited Violation (NCV) were identified.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP 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.

A. Inspector-Identified and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance due to the licensees failure to perform operability determinations/evaluations for non-safety related structures, systems, or components discussed in the Updated Final Safety Analysis Report which were discovered to be degraded.

This finding was more than minor because if left uncorrected, the failure to properly evaluate the continued operability of degraded equipment could result in the licensee inappropriately relying on structures, systems, or components that were unable to perform their safety function during an initiating event. The finding also impacted the cross-cutting area of problem identification and resolution because the licensee has had multiple examples of failures to initiate operability determinations or evaluations which had not been previously identified. No violation of NRC requirements occurred since the completion of operability determinations/evaluations was not required by NRC regulations. (Section 4OA2.2).

Green.

The inspectors identified a NCV of 10 CFR 50.65(a)(4). Specifically, the NRC identified that the licensee non-conservatively evaluated the on-line risk associated with actions taken in response to an emergent residual heat removal service water leak on January 14, 2003.

The inspectors considered this issue of more than minor significance because, had an adequate risk evaluation occurred, the on-line risk would have changed from Green to

Yellow.

The inspectors determined that the issue was of very low safety significance, or Green, because although one train of residual heat removal service water was unavailable, the actual safety function of the system could have been performed by the remaining train and the train was not inoperable for greater than the Technical Specification allowed outage time. Corrective actions for this issue included providing training to operations personnel which focused on crediting manual operator actions in place of automatic actions as part of a risk assessment. (Section 4OA5).

Licensee-Identified Violations

Violations of very low safety significance, which were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at approximately 85 percent power during the inspection period with the exception of planned power reductions on February 6 and 27, 2005, to perform control rod adjustments. On March 21, 2005, operations personnel shut down Unit 1 to begin refueling outage Q1R18. Refueling outage activities included replacement of the main power transformer, one switchyard breaker, a reactor recirculation pump motor and the low pressure turbine buckets, maintenance on multiple risk significant systems, and various other activities. Unit 1 remained shut down at the conclusion of the inspection period.

Unit 2 also operated at approximately 85 percent power during the period with the exception of planned power reductions for control rod special maneuvers and scram time testing on January 9, 2005, and turbine valve testing on March 27,

REACTOR SAFETY

Cornerstone: Initiating Events, Mitigating Systems, Barrier Integrity, and

Emergency Preparedness

1R01 Adverse Weather

a. Inspection Scope

On March 30, 2005, Quad Cities Station experienced severe thunderstorms and sustained winds greater than 40 miles per hour. Prior to the severe weathers arrival, the inspectors observed activities in the control room to determine the preparations being taken to address the approaching storm and the potential impact on equipment.

The inspectors noted that the operations field supervisor had performed a tour of the outside areas to identify and address potential missiles. In addition, operations personnel in the control room were routinely monitoring weather radar and wind speed information. During discussions with the shift manager and the unit supervisors, the inspectors learned that both units had entered an increased risk condition due to the expected weather. In addition, operations personnel discussed the equipment available to each unit in the event a loss of offsite power occurred during the storm. This was extremely important as the amount of electrical equipment available on Unit 1 was limited due to refueling outage activities. The licensee also discussed the need to stop activities on the refueling floor if sustained winds of greater than 40 miles per hour were observed. This represented the completion of one inspection sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the following risk-significant mitigating systems equipment during times when the equipment was of increased importance due to redundant systems or other equipment being unavailable:

• Unit 1 Reactor Core Isolation Cooling System;

• Safe Shutdown Makeup Pump and the Unit 2 Reactor Core Isolation Cooling System;

• Residual Heat Removal Service Water Loop 1A; and

• Unit 1 A Core Spray System.

The inspectors utilized the valve and breaker checklists listed at the end of this report to verify that the components were properly positioned and that support systems were lined up as needed. The inspectors examined the material condition of the components and observed equipment operating parameters to verify that there were no obvious deficiencies. The inspectors reviewed outstanding work orders and issue reports associated with each system to verify that those documents did not reveal issues that could affect the equipment inspected. The inspectors also used the information in the appropriate sections of the Updated Final Safety Analysis Report to determine the functional requirements of the systems. This review constituted the completion of four inspection samples.

b. Findings

No findings of significance were identified.

.2 Complete Walkdown

a. Inspection Scope

During the inspection period, the inspectors conducted an in-depth review and walkdown of the reactor protection system. This system was selected due to its high safety significance and risk significance. The inspection consisted of the following activities:

• a review of plant procedures (including selected abnormal and emergency procedures), drawings, the system health report, Technical Specifications, and the Updated Final Safety Analysis Report to determine overall system health, proper system configuration, and the systems licensing basis;

• a review of outstanding maintenance work requests to determine items in need of repair;

• a review of system predefines to determine if preventive maintenance was completed as recommended;

• a review of predefine deferrals to evaluate the licensees justification for not conducting recommended preventive maintenance tasks;

• a review of outstanding or completed temporary and permanent modifications to the system; and

• an electrical and/or mechanical walkdown of the system to verify proper alignment, component accessibility, availability, and condition.

The inspectors also reviewed selected issues documented in issue reports to verify that the issues were appropriately addressed. This review constituted the completion of one semi-annual walkdown sample.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Quarterly Fire Zone Walkdowns

a. Inspection Scope

The inspectors performed routine walkdowns of accessible portions of the following risk significance fire zones:

• Fire Zone 1.1.1.2 - Unit 1 Reactor Building First Floor;

• Fire Zone 8.2.6.C - Unit 1/2 Ground Floor;

• Fire Zone 11.1.3 - Unit 1 High Pressure Coolant Injection and Tunnel;

• Fire Zone 11.1.4 - Unit 2 High Pressure Coolant Injection; and

• Various Fire Zones - Station Blackout Diesel Generator Building.

The inspectors verified that transient combustibles were controlled in accordance with the licensees procedures. During a walkdown of each fire zone, the inspectors observed the physical condition of fire suppression devices and passive fire protection equipment such as fire doors, barriers, and penetration seals. The inspectors observed the condition and placement of fire extinguishers and hoses against the Pre-Fire Plan fire zone maps. The physical condition of accessible passive fire protection features such as fire doors, fire dampers, fire barriers, fire zone penetration seals, and fire retardant structural steel coatings were also inspected to verify proper installation and physical condition. Lastly, the inspectors reviewed the licensees corrective action program database to ensure that fire protection-related issues were being entered into the program for resolution. This review constituted the completion of five inspection samples.

b. Findings

No findings of significance were identified.

.2 Fire Drill Observation

a. Inspection Scope

On February 8, 2005, the inspectors observed the licensees fire brigade participate in a quarterly fire drill. The drill scenario consisted of a fire in the Unit 2A reactor feedwater pump auxiliary oil pump skid. Upon hearing the fire alarm, the inspectors observed the fire brigade members don their protective equipment to ensure that the brigade members were appropriately protected from the fire. The inspectors also observed the actions performed by and communications provided by the fire brigade leader to ensure that the leader demonstrated adequate command and control responsibilities, selected an appropriate staging area, performed a proper size up of the fire, selected the proper fire attack strategies, addressed potential adverse impacts on the plant, recognized the need for offsite assistance by local fire departments, and communicated with the control room. Lastly, the inspectors observed the fire brigade members during the fire attack to evaluate the appropriateness of their actions. This inspection represented the completion of one annual fire drill inspection sample.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

On January 5, 2005, the inspectors observed engineering and operations personnel complete performance testing on the 1B residual heat removal heat exchanger. This heat exchanger was chosen for inspection due to its high safety significance and risk significance. During the testing observation the inspectors verified that the acceptance criteria and test results considered differences between test and design basis conditions because testing at the design heat removal rate was not practical. The inspectors performed independent calculations using the licensees test results to confirm that the results considered possible uncertainties and that the heat exchanger remained capable of performing its safety function.

During the Unit 1 refueling outage, the inspectors performed a visual inspection of the Unit 1 emergency diesel generator heat exchanger internals. Prior to performing the inspection, the inspectors reviewed the licensees heat exchanger inspection procedures to ensure that all areas of the heat exchanger were addressed. The inspectors verified that the licensees procedures contained appropriate acceptance criteria. Very little corrosion was identified during the visual inspections. The inspectors also reviewed heat sink-related issue reports generated within the last year to ensure that the issues were being entered into the corrective action program with the appropriate characterization and significance. While inspecting the re-installation of the heat exchanger end bells, the inspectors identified a thread engagement issue on the B heat exchanger. The licensee documented this issue in Issue Reports 319103 and 319205. This review constituted the completion of two annual inspection samples.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

On February 17, 2005, the inspectors observed two operations crews in the simulator.

Each crews performance was evaluated using a different scenario. The first scenario consisted of a reactor vessel level instrument failure, the loss of the A reactor protection system motor generator set, a control rod scram and drift, a fuel failure, a Group I isolation failure, a leak outside containment, and the need to manually blow down the reactor. The second scenario involved an average power range monitor failure, a reactor protection system channel failure, a control rod scram and drift, fuel failure, a turbine building steam leak, and the need to manually blow down the reactor.

The inspectors evaluated each crews performance in the areas of:

• clarity and formality of communications;

• ability to make timely actions in the safe direction;

• prioritization, interpretation, and verification of alarms;

• procedure use;

• control board manipulations;

• oversight and direction from supervisors; and

• group dynamics.

Crew performance in the above areas was compared to licensee management expectations and guidelines as presented in the following documents:

• OP-AA-101-111, Rules and Responsibilities of On-Shift Personnel;

• OP-AA-103-102, Watchstanding Practices;

• OP-AA-103-104, Reactivity Management Controls; and

• OP-AA-104-101, Communications.

The inspectors verified that each crew completed the critical tasks listed in the above scenarios. If critical tasks were not met, the inspectors verified that crew and operator performance errors were detected and adequately addressed by the evaluators. The inspectors verified that the evaluators effectively identified crews or individuals requiring remediation and appropriately indicated when removal from shift activities was warranted. The inspectors observed the licensees critique to verify that weaknesses identified during this observation were noted by the evaluators and discussed with the respective crews. This review constituted the completion of two inspection samples.

b. Findings

No findings of significance were identified.

1R12 Maintenance Implementation

a. Inspection Scope

The inspectors reviewed the licensees handling of performance issues and the associated implementation of the Maintenance Rule (10 CFR 50.65) to evaluate maintenance effectiveness for the systems listed below. These systems were selected based on them being designated as risk significant under the Maintenance Rule, being in increased monitoring (Maintenance Rule category a(1) group), or due to an inspector identified issue or problem that potentially impacted system work practices, reliability, or common cause failures:

• Residual Heat Removal Service Water System;

• Automatic Depressurization System; and

• Turbine Building Closed Cooling Water System.

The inspectors review included an examination of specific system issues, an evaluation of maintenance rule performance criteria, maintenance work practices, common cause issues, extent of condition reviews, and trending of key parameters. The inspectors also reviewed the licensees maintenance rule scoping, goal setting, performance monitoring, functional failure determinations, and current equipment performance status. This review constituted the completion of three inspection samples.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

The inspectors reviewed the documents listed in the List of Documents Reviewed section of this report to determine if the risk associated with the listed activities agreed with the results provided by the licensees risk assessment tool. The inspectors conducted walkdowns to ensure that redundant mitigating systems credited by the licensees risk assessment remained available. When compensatory actions were required, the inspectors conducted plant tours to validate that the compensatory actions were implemented. The inspectors discussed emergent work activities with the shift manager and work week manager to ensure that these additional activities did not change the risk assessment results. Lastly, the inspectors performed a word search review of the licensees corrective action database to ensure that problems related to risk assessments were entered into the licensees corrective action program. This review represented the completion of ten inspection samples.

• Work Week January 3-8, 2005, including planned maintenance on the control room emergency ventilation system, the switchyard, and the circulating water bays;

• Work Week January 10-16, 2005, including planned maintenance on the B fire diesel system and testing on the automatic depressurization system logic;

• Work Week January 17-23, 2005, including planned maintenance on the Unit 1 high pressure coolant injection system and the Unit 1 condensate demineralization system;

• Work Week January 24-29, 2005, including planned maintenance on the 1C reactor feedwater pump, the 1B electrohydraulic control system, the Unit 1 reactor core isolation cooling system, and the Unit 1 high pressure coolant injection system;

• An evaluation of an emergent work condition identified on the 1B residual heat removal service water system on February 10, 2005;

• Work Week February 20-25, 2005, including surveillance testing on the Unit 1 core spray system which made several risk significant systems inoperable and planned maintenance in the switchyard and anticipated transient without scram breakers;

• Work Week March 6-12, 2005, including planned maintenance in the switchyard and surveillance testing on the Unit 1 anticipated transient without scram relays and logic, the Unit 1 125 Volt battery, and the Unit 2 reactor core isolation cooling system;

• An evaluation of a previously identified issue regarding the risk associated with residual heat removal service water maintenance;

• An evaluation of the risk associated with a predicted switchyard low voltage condition; and

• An evaluation of the risk associated with the unexpected loss of Busses 18 and 19.

b. Findings

The inspectors identified one Green finding and one Non-Cited Violation (NCV) during their review. See Section 4OA5 for details.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors assessed the following operability evaluations or issue reports associated with equipment operability issues:

• Issue Report 236954 - Unit 1 Drywell Floor Drain Sump Pump Tripped Thermals;

• Issue Report 209270 - Unit 2 B Feedwater Heater Shells May Go Below Minimum Wall Thickness Before Next Refueling Outage;

• Issue Report 223039 - Turbine Control Valve #3 Failed to Fast Close During Testing;

• Issue Report 285762 - Unit 1 Core Recirc Flow Loop B Indication;

• Operability Evaluation 296236 - Unit 2 125 VDC System Ground;

• Issue Report 300636 - Minimum Wall Requirement for RHRSW Line 1-1005B-16 Not Met;

• Issue Report 301135 - Repair/Examination of Line 1-1005A-16" is Required;

• Issue Report 298438 - Potential for Electromatic Relief Valves Not to De-Energize During Loss of Coolant Accident Conditions; and

• Issue Report 309971 - Control Rod Drive Hydraulic Control Unit Accumulators Installed with Split Flanges.

The inspectors reviewed the technical adequacy of the evaluation against the Technical Specifications, Updated Final Safety Analysis Report, and other design information; determined whether compensatory measures, if needed, were taken; and determined whether the evaluations were consistent with the requirements of LS-AA-105, Operability Determination Process, Revision 0.

In addition, the inspectors reviewed selected issues that the licensee entered into its corrective actions program to verify that identified problems were being entered into the program with the appropriate characterization and significance. This review represented the completion of nine inspection samples.

b. Findings

One Green finding was identified due to the licensees failure to initiate operability determinations/evaluations for equipment discussed in the Updated Final Safety Analysis Report which was determined to be degraded. See Section 4OA2.2 of this report for additional details.

1R16 Operator Workarounds

a. Inspection Scope

The inspectors assessed the operator workaround listed below to determine the potential effects on the functionality of the corresponding mitigating systems. During these inspections, the inspectors reviewed the technical adequacy of the workaround documentation against the Updated Final Safety Analysis Report and other design information to assess whether the workaround conflicted with any design basis information. The inspectors also compared the information in abnormal or emergency operating procedures to the workaround information to ensure that the operators maintained the ability to implement important procedures when needed. This review represented the completion of one inspection sample.

• Operator Workaround 04-013 - Degraded Switchyard Voltage Issues and Transformer Loading Concerns During a Loss of Coolant Accident.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications

a. Inspection Scope

During the inspection period, the inspectors reviewed the following permanent plant modifications:

• Engineering Change 352570, Permanent Repair of Service Water Header 1-3902-30" - O Branch Leak on Header Side of 1-3999-685 Valve, Revision 0; and

• Engineering Change 351170, Reactor Building Opening and Replacement Siding, Revision 0.

The inspectors reviewed the design adequacy of the modifications by verifying one or more of the following:

• energy requirements were able to be supplied by supporting systems under accident and event conditions;

• replacement components were compatible with physical interfaces;

• replacement component properties met functional requirements under event and accident conditions;

• replacement components were environmentally and seismically qualified;

• sequence changes remained bounded by the accident analyses and loading on support systems was acceptable;

• response times for structures, systems, and components were sufficient to serve accident and event functional requirements assumed by the design analyses;

• control signals were appropriate under accident and event conditions; and

• affected operations procedures were revised and training needs were evaluated in accordance with station administrative procedures.

The inspectors verified that the post modification testing demonstrated system operability by verifying no unintended system interactions occurred, system performance characteristics met the design basis, and post-modification testing results met all acceptance criteria. The inspectors also reviewed issue reports related to permanent plant modifications to ensure that the licensee was entering issues into their corrective action program at an appropriate threshold. These reviews represented the completion of two inspection samples.

b. Findings

Engineering Change 351170 and two temporary modifications listed in Section 1R23 of this report, were developed in support of the steam dryer replacement project.

Engineering Change 351170 was initiated to allow the removal and replacement of portions of the reactor building siding. Engineering Changes 351171 and 351277 governed the installation of a new exterior door and a temporary steam dryer enclosure.

While reviewing these modifications, the inspectors developed a concern regarding the safety classification of the modifications. Specifically, the licensee had classified each of these modifications as non-safety related even though the reactor building siding, the door, and the enclosure would each serve as part of the secondary containment structure at certain times. In addition, the inadequate classification may have resulted in the licensee installing these modifications without implementing the additional checks and balances required for a safety-related modification.

The inspectors discussed this concern with engineering and regulatory assurance personnel. During these discussions, the inspectors were presented with information which appeared to support the licensees decision to classify these modifications as non-safety related. The inspectors performed a review of previous NRC documents pertaining to the reactor building siding and identified information which conflicted with the licensees information. The inspectors provided all of the information to members of the Office of Nuclear Reactor Regulation for additional review and a final determination regarding the appropriate safety classification.

At the conclusion of the inspection period, the licensee had performed evaluations and testing which demonstrated that the door and enclosure could perform the same functions as the existing secondary containment structure. However, the Office of Nuclear Reactor Regulation had not yet determined whether the licensee had appropriately classified the modifications discussed above. As a result, the inspectors considered this item to be unresolved pending a final decision by the Office of Nuclear Reactor Regulation (URI 05000254/2005002-01; 05000265/2005002-01).

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post maintenance testing activities listed below during the inspection period:

• Corrective maintenance on the Unit 1 high pressure coolant injection inlet drain pot performed using Work Order 765685;

• Emergent maintenance to replace two agastat relays in the Unit 1 high pressure coolant injection system logic performed using Work Orders 7656936 and 774282;

• Corrective maintenance on the Unit 1 C reactor feedwater pump performed using Work Order 435249;

• Installation of steam dryer enclosure and door on refuel floor using Work Order 731537;

• Repair of Unit 1 source range monitor 24 using Work Order 637456; and

• Troubleshooting associated with the unexpected failure of the Transformer 22 to Bus 24 breaker.

For each post maintenance activity selected, the inspectors reviewed the Technical Specifications and Updated Final Safety Analysis Report against the maintenance work package to determine the safety function(s) that may have been affected by the maintenance. Following this review the inspectors verified that the post maintenance test activity adequately tested the safety function(s) affected by the maintenance, that acceptance criteria were consistent with licensing and design basis information, and that the procedure was properly reviewed and approved. When possible the inspectors observed the post maintenance testing activity and verified that the structure, system, or component operated as expected; test equipment used was within its required range and accuracy; jumpers and lifted leads were appropriately controlled; test results were accurate, complete, and valid; test equipment was removed after testing; and any problems identified during testing were appropriately documented. These reviews represented the completion of six inspection samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities

a. Inspection Scope

The inspectors reviewed the licensees outage schedule, verified equipment alignments, and observed control room and outage activities. The inspectors verified that the licensee effectively conducted the shutdown; managed elements of risk pertaining to reactivity control during and after the shutdown; and implemented decay heat removal system procedure requirements as applicable.

The inspectors performed the following activities daily:

• attended control room operator and outage management turnover meetings to verify that the current shutdown risk status was well understood and communicated;

• performed walkdowns of the main control room to observe the alignment of systems important to shutdown risk;

• performed periodic walkdowns of the turbine and reactor buildings to observe ongoing work activities; and

• reviewed selected issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance.

Additionally, the inspectors observed the following specific activities, as appropriate:

• shutdown and cooldown to a cold shutdown condition (MODE 4);

• implementation of abnormal operating procedures to address any abnormal occurrences;

• initiation of the shutdown cooling mode of the residual heat removal system;

• control rod withdrawals to criticality and portions of the plant power ascension;

• surveillance tests throughout the duration of the outage;

• troubleshooting efforts for emergent plant equipment issues; and

• reactor vessel disassembly.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed surveillance testing activities and/or reviewed completed surveillance test packages for the tests listed below:

• QCOS 0203-08, Unit 1 On-line Automatic Blowdown Logic Test;

• QCIS 1300-03, Reactor Core Isolation Cooling Steam Line High Flow Calibration and Functional Test, and QCOS 1300-06, Reactor Core Isolation Cooling System Power Operated Valve Test;

• QCOS 1300-18, Reactor Core Isolation Cooling Drain Pot Level Switch and Drain Valve Operability Test, and QCOS 1300-22, Reactor Core Isolation Cooling Contaminated Condensate Storage Tank Suction Check Valve Closure Test;

• QCOS 1400-12, Unit 1 Core Spray Logic Functional Test;

• QCOS 2300-07, High Pressure Coolant Injection Pump Performance Test;

• QCOS 2300-29, Unit 1 High Pressure Coolant Injection System Logic Functional Test;

• QCOS 3200-04, Reactor Feedwater Check Valve 1-220-59A/B and Safe Shutdown Injection Check Valve Closure Test;

• MA-AB-725-112, Preventive Maintenance Inspection of General Electric 480 Volt Circuit Breakers and Cubicles;

• QCTS 0920-04, Source Range Monitoring and Intermediate Range Monitoring Overlap Testing;

• QCTS 0750-05, Snubber Functional Testing; and

• QCTS 0600-05, Main Steam Isolation Valve Local Leak Rate Testing.

The inspectors verified that the structures, systems, components, or barriers tested were capable of performing their intended safety function by comparing the surveillance procedure or calibration acceptance criteria and results to design basis information contained in Technical Specifications, the Updated Final Safety Analysis Report, and licensee procedures. The inspectors verified that each test was performed as written, the data was complete and met the requirements of the procedure, and the test equipment range and accuracy were consistent with the application by observing the performance of the activity. Following test completion, the inspectors conducted walkdowns of the associated areas to verify that test equipment had been removed and that the system or component was returned to its normal standby configuration. The inspectors also reviewed actions taken in response to Issue Report 310140 which was generated during the inspections. The reviews listed above represented the completion of eleven inspection samples.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed documentation for and installation of the following temporary configuration changes:

• Engineering Change 347977 - Steam Dryer Replacement Project Platform Installation and Removal;

• Temporary Configuration Change 353675 - Disable 151N Relays for Bus 13 and 14 Main and Reserve Feed Breakers;

• Engineering Change 351323 - Using the Alternate 125 Volt Battery as a 250 Volt Battery Substitute;

• Engineering Change 351277 - Unit 1 Steam Dryer Temporary Enclosure;

• Engineering Change 351171 - Enclosure Exterior Door, Semi-Permanent Hardware, and Sheet Metal Panels; and

• Engineering Change 350830 - Addition of Instrumentation Feedthrough Modules at X-102B and Rework of Drywell Vent Booster Fan Power Cable.

The inspectors assessed the acceptability of each temporary configuration change by comparing the 10 CFR 50.59 screening and evaluation (if required) and design information against the Updated Final Safety Analysis Report and Technical Specifications. The comparisons were performed to ensure that the new configurations remained consistent with design basis information. The inspectors performed field verifications to ensure that the modifications were installed as directed; the modifications operated as expected; modification testing adequately demonstrated continued system operability, availability, and reliability, and that operation of the modifications did not impact the operability of any interfacing systems. The inspectors also reviewed condition reports initiated during or following the temporary modification installation to ensure that problems encountered during the installation were appropriately resolved.

This review represented the completion of six inspection samples.

b. Findings

No findings of significance were identified. However, see Section 1R17 of this report for discussion of an unresolved item related to Engineering Changes 351171 and 351277.

1EP2 Alert and Notification System Testing

a. Inspection Scope

The inspectors discussed with corporate and station-based Emergency Preparedness staffs the operation, maintenance, and periodic testing of the Alert and Notification System in the Quad Cities Nuclear Power Stations plume pathway Emergency Planning Zone to determine whether the Alert and Notification System equipment was adequately maintained and tested in accordance with Emergency Plan commitments and procedures. The inspectors reviewed records of 2003 and 2004 preventive and non-scheduled maintenance activities, as well as July 2004 through December 2004 Alert and Notification System operability test results.

These activities completed one inspection sample.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation Testing

a. Inspection Scope

The inspectors reviewed and discussed with station emergency preparedness staff the procedures that included the primary and alternate methods of initiating an emergency response organization activation to augment the onshift emergency response organization and the provisions for maintaining the stations emergency response organization call-out roster. The inspectors also reviewed reports and a sample of corrective action program records of unannounced off-hours augmentation drills, which were conducted monthly between January 2003 and December 2004, to determine the adequacy of the drills critiques and associated corrective actions. The inspectors also reviewed the emergency preparedness training records of a random sample of 75 Quad Cities Nuclear Power Station emergency response organization members, who were assigned to key and support positions, to determine whether they were currently trained for their assigned emergency response organization positions.

These activities completed one inspection sample.

b. Findings

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspectors performed a screening review of Revision 16 of the Exelon Standardized Emergency Plan and reviewed the licensees 50.54(q) evaluation of the changes identified in Revision 16 to determine whether these changes decreased the effectiveness of the licensees emergency planning for its Illinois nuclear power stations. The inspectors also performed a screening review of the associated Revision 19 of the Quad Cities Annex to the Standardized Emergency Plan and both 50.54(q) evaluations of the changes incorporated in Revision 19 to determine whether changes identified in Revision 19 decreased the effectiveness of the licensees emergency planning for the Quad Cities Nuclear Power Station. The inspectors reviewed a sample of letters of agreement with offsite support organizations associated with the Quad Cities Nuclear Power Station to determine whether these agreements were current and whether the types of support to be provided were consistent with statements in the Quad Cities Annex to the Standardized Emergency Plan. This review did not constitute an approval of the changes, and as such, the changes are subject to future NRC inspection to ensure that the emergency plan continues to meet NRC regulations.

These activities completed one inspection sample.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspectors reviewed a sample of nuclear oversight staffs 2003 and 2004 audits and objective evidence reports on the Quad Cities Nuclear Power Stations emergency preparedness program to verify that these independent assessments met the requirements of 10 CFR 50.54(t). The inspectors also reviewed critique reports and samples of corrective action program records associated with those audits and with two actual emergency events that occurred in 2003 and 2004. The inspectors reviewed critique reports and samples of corrective action program records associated with the 2004 biennial exercise, as well as various emergency preparedness drills conducted in 2003 and 2004, in order to verify that the licensee fulfilled its drill commitments and to evaluate the licensees efforts to identify, track, and resolve concerns identified during these activities. The inspectors also reviewed samples of implementing procedure revisions that were associated with corrective action records to verify that these procedures were adequately revised.

These activities completed one inspection sample.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors conducted several emergency preparedness drill observations during the inspection period. As part of the first observation, the inspectors evaluated an operations crew during a simulator drill on January 10, 2005. The simulator scenario involved a loss of normal feedwater, a loss of coolant accident, the loss of Bus 14-1, and a manual blowdown of the reactor vessel.

On March 4, 2005, the inspectors observed members of the licensees emergency preparedness organization in both the simulator and the technical support center during a planned emergency preparedness performance indicator drill. The drill scenario consisted of flooding in the 1B residual heat removal room, a reactor water cleanup system leak, an anticipated transient without scram, the failure of the main steam isolation valves to close, a fuel failure, and a simulated release of radioactivity to the environment.

During the drills the inspectors ensured that event classification, notifications, and protective action recommendations were timely, accurate, and correctly communicated by reviewing actual plant data, notification worksheets, and observing actual drill activities. The inspectors also attended the licensees drill critiques to ensure that any weaknesses or deficiencies noted during the drill were also recognized by the licensees drill evaluators. These observations represented the completion of three inspection samples.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Reactor Safety Strategic Areas

a. Inspection Scope

The inspectors reviewed the licensees records associated with the three emergency preparedness performance indicators listed below. The inspectors verified that the licensee accurately reported these indicators in accordance with relevant procedures and Nuclear Energy Institute guidance endorsed by the NRC. Specifically, the inspectors reviewed licensee records associated with performance indicator data reported to the NRC for the period July 2004 through December 2004. Reviewed records included: procedural guidance on assessing opportunities for the three performance indicators; assessments of performance indicator opportunities during pre-designated Control Room Simulator training sessions, the 2004 biennial exercise, and mini-drills; revisions of the roster of personnel assigned to key emergency response organization positions; and results of periodic Alert and Notification System operability tests. The following performance indicators were reviewed:

Common

• Alert and Notification System;

• Emergency Response Organization Drill Participation; and

• Drill and Exercise Performance.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action system at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Minor issues entered into the licensees corrective action system as a result of the inspectors observations are included in the respective inspection scopes of each section of this report.

b. Findings

No findings of significance were identified.

.2 Review of Operability Determination/Evaluation and Operational Decision Making

Processes

a. Inspection Scope

During the daily review of issue reports, the inspectors identified several concerns with the processing of reports which documented the degradation of equipment discussed in the Updated Final Safety Analysis Report. The inspectors selected the following issue reports for additional review to verify that the licensee had appropriately evaluated whether the degraded equipment would continue to perform its specified function using the operability determination and evaluation process. This review represented the completion of one annual inspection sample.

• Issue Report 236954 - Drywell Floor Drain Sump Pump 1B Degraded;

• Issue Report 209270 - B Feedwater Heater Shells May Go Below Minimum Wall by Q2R18;

• Issue Report 223039 - Turbine Control Valve #3 Failed to Fast Close During Testing; and

• Issue Report 285762 - Unit 1 Core Recirculation Flow Loop B Indication.

b. Findings

The inspectors determined that the licensee had effectively identified problems with the degraded equipment. However, the inspectors were concerned with the licensees evaluation and prioritization of each issue. The inspectors identified a Green finding due to the licensees failure to initiate operability determinations/evaluations when required and the failure to evaluate compensatory measures as described in Generic Letter 91-18 and Procedure LS-AA-105.

Description of Concerns Drywell Floor Drain Sump Pump 1B Degraded The inspectors reviewed this issue and determined that problems with the 1B drywell floor drain sump pump thermal overloads tripping began on June 30, 2004. During this event, the licensee reset the thermal overloads and restored the pump to an operable status. On July 8, 2004, maintenance personnel initiated Issue Report 234582 when they discovered errors in setting the floor drain sump pump clearances. The issue report initiator hypothesized that the June 30 pump trip could have been due to having inadequate pump clearances. The licensee developed several actions in response to the July 8 issue report. However, none of these actions evaluated the possible connection between the inadequate clearances and the June 30 pump trip. The licensee initiated Issue Report 236954 on July 18, 2004, when a second trip of the 1B drywell floor drain sump pump occurred. The inspectors reviewed these issue reports in the aggregate and were concerned that the licensee had not completed an operability determination/evaluation even though there was information which indicated that the pump was degraded.

The inspectors conducted a control room tour and discovered that an information tag had been placed on the control switch for the 1B drywell floor drain sump pump. In addition, the switch had been placed in the pull to lock position. The inspectors discussed the information tag and the switch position with the control room operators.

The operators explained that many personnel suspected that the thermal overloads actuated due to the presence of foreign material in the pumps suction. In late July, 2004 maintenance personnel switched the pump motors electrical leads in an effort to expel the foreign material by making the pump operate backwards. However, this troubleshooting was unsuccessful. The inspectors questioned the operators regarding whether the sump pump was inoperable or operable but degraded. No clear answers were provided. Instead, operations personnel restated that the pumps control switch was in the pull-to-lock position.

The inspectors reviewed Generic Letter 91-18 and determined that operability determinations and evaluations were to be performed for any structure, system, or component described in the Updated Final Safety Analysis Report. The inspectors reviewed the Updated Final Safety Analysis Report and found that Updated Final Safety Analysis Report Section 9.3 clearly described the drywell floor drain system as having two pumps. The inspectors interviewed several members of the operations department about this issue. In addition, the inspectors conducted an additional review of Issue Report 236954 to determine whether the issue report provided a basis for continued operability of the 1B drywell floor drain sump pump. Within the body of the issue report, the initiator stated that the operation of the 1B drywell floor drain sump pump was questionable. The licensees procedure and Generic Letter 91-18 clearly stated that the operability of equipment cannot be indeterminate. As a result, operations personnel should have declared the sump pump inoperable. However, operations personnel determined that an operability determination was not necessary since the remaining drywell floor drain sump pump was fully operable and the degraded pump did not result in an entry into the Technical Specifications.

The inspectors also discussed this issue with operations management. Operations management informed the inspectors that an operability determination/evaluation was not required because the Updated Final Safety Analysis Report statement describing the drywell floor drain system as a two pump system was in place to better explain the system features rather than the design and licensing basis of the system. The inspectors performed an additional review of the Updated Final Safety Analysis Report and disagreed with the licensees position. This disagreement was based upon the fact that the Updated Final Safety Analysis Report clearly described each pump as having its own function. Specifically, one pump was designed to start when a high sump level condition occurred. The other pump was designed to start during a high-high sump level condition.

The inspectors discussed this information with operations personnel. The inspectors were informed that the licensee had changed how they operated the drywell floor drain sump pumps several years ago. Currently, the licensee maintained the drywell floor drain sump pump discharge valves in the closed position. As a result, the sump pumps were unable to start automatically as described in the Updated Final Safety Analysis Report. In addition, it appeared the licensee had substituted a manual action in place of an automatic action without evaluating the potential impacts of the manual actions. The licensee was evaluating this issue at the conclusion of the inspection period. Therefore, the inspectors considered this item to be unresolved pending a review of the licensees evaluation (URI 05000254/2005002-02; 05000265/2005002-02).

B Feedwater Heater Shells May Go Below Minimum Wall by Q2R18 Issue Report 209270 was initiated in March 2004 when licensee personnel discovered that two of the feedwater heater shell sections could degrade below the American Society of Mechanical Engineers,Section VIII, code required minimum wall thickness of 0.112 inches prior to the next refueling outage. The inspectors reviewed the Updated Final Safety Analysis Report and found that the feedwater heaters were discussed in Section 10.4.7. As a result, the inspectors concluded that an operability determination/evaluation needed to be performed prior to the heater shells degrading below minimum wall requirements to ensure that the heaters would continue to perform their intended function.

Procedure LS-AA-105, Operability Determinations, provided allowances for documenting operability determinations within the body of an issue report. However, the initiator was expected to provide enough detail in the issue report to clearly demonstrate that continued operability was maintained. The inspectors reviewed Issue Report 209270 and found a reference to an engineering evaluation on the heaters.

However, the issue report contained very few of the evaluations details. As a result, the inspectors were unable to determine if the continued operability of the feedwater heaters could be maintained throughout the operating cycle.

During a review of the licensees operational decision making document (a non-corrective action document) for this issue, the inspectors found that a copy of the engineering evaluation had been attached. The inspectors determined that the engineering evaluation was very detailed and provided a comprehensive discussion on the condition of the feedwater heaters. However, the inspectors were concerned that the licensee had not recognized the need to include a copy of the evaluation as part of the issue report in order to support continued operability of the heaters.

Turbine Control Valve #3 Failed to Fast Close During Testing This issue report was initiated in May 2004 due to the failure of the turbine control valve #3 fast-acting solenoid to actuate during testing. The licensee entered Technical Specification 3.3.1.1, Reactor Protection System Instrumentation, since they were unable to determine whether the valves failure to close was due to a faulty pressure switch (which provides an input into the reactor protection system) or a degraded solenoid. In addition, operations personnel requested that engineering perform an operability evaluation to ensure that the reactor protection system functions provided by the pressure switch remained operable.

During subsequent troubleshooting activities, the licensee determined that the fast-acting solenoid was degraded rather than the pressure switch. Based upon this information, and a determination that the reactor protection system inputs were not impacted, operations personnel canceled the operability evaluation request. The decision to cancel the operability evaluation concerned the inspectors for two reasons.

First, the issue report clearly stated that operation of the fast-acting solenoid was credited in the Updated Final Safety Analysis Report for load rejection without bypass events and loss of alternating current/loss of grid events. However, the decision to cancel the operability evaluation was based solely upon the ability to meet Technical Specifications. This demonstrated that operations personnel were not familiar with the requirement to perform operability evaluations on equipment described in the Updated Final Safety Analysis Report. Second, the issue report stated that the core operating limits report required a penalty to be applied to the core thermal limits due to the degraded solenoid. Per the operability evaluation process, the penalty application should have been considered a potential compensatory measure. Since the operability evaluation was not performed, the possibility of potential compensatory measures was not considered. After consultation with an NRC operability specialist, the inspectors subsequently determined that implementing a Core Operating Limits Report penalty was not a compensatory measure.

Unit 1 Core Recirculation Flow Loop B Indication In December 2004 the licensee initiated Issue Report 285762 which documented the need to calibrate one of the Unit 1 core flow indications more frequently. The inspectors reviewed the issue report and found that operations personnel were concerned with the degraded indication because it had the potential to adversely impact the daily jet pump surveillances and could result in unknowingly exceeding Technical Specification limits.

Although operations personnel were concerned with the degraded flow indication, they determined that the indication remained operable since all of the Technical Specification requirements were being met. In addition, Operational Decision Making Document 04-049 was developed to address continued plant operation with the degraded indication and the possible repair options.

The inspectors reviewed the operational decision making document and found that this document contained information which had not been included in the issue report.

Specifically:

• The degraded indicator had been calibrated four to five times between March and December 2004. The normal calibration frequency was approximately six months;

• The time between calibrations was decreasing while the magnitude of the deviation between indications was increasing at a much quicker rate;

• The indicator would be calibrated on an as-needed basis until it could be repaired; and

• The impact of the degraded indicator on plant operations was that the thermal limit calculations and flow control line determinations were more conservative.

The inspectors determined that portions of the operational decision making document information were very similar to information that would be included in an operability determination or evaluation. The inspectors were also concerned that the decision to calibrate the indication more frequently (in an effort to keep the indication operable)needed to be evaluated as a compensatory measure. The inspectors discussed their concerns with operations and regulatory assurance personnel. Operations personnel explained that the need for an operability determination or evaluation was not considered since the degraded indication continued to meet the Technical Specification requirements. As a result, the compensatory measure was not evaluated.

Analysis of Risk Significance and Enforcement The inspectors determined that the failure to initiate operability determinations or evaluations when required was a performance deficiency warranting a significance evaluation. The inspectors determined that the issue was more than minor because if left uncorrected, the failure to evaluate degraded equipment using the operability determination and evaluation process could become a more significant issue. The finding also impacted the cross-cutting area of problem identification and resolution because the licensee has had multiple examples of failures to initiate operability determinations or evaluations in accordance with LS-AA-05.

The inspectors completed a significance determination for each piece of degraded equipment using Inspection Manual Chapter 0609, Significance Determination Process. This finding was determined to be of very low safety significance (Green)because the degraded pieces of equipment did not result in a total loss of safety function of any system. Although the licensee failed to perform operability determinations and evaluations in accordance with their procedure, no violation of NRC requirements occurred since this procedure is not required by any current NRC regulations (FIN 05000254/2005002-03; 05000265/2005002-03). A description of the licensees corrective actions is included in the following section.

Licensees Corrective Actions The licensee initiated Issue Report 311612 to document the inspectors concerns. The licensees corrective actions consisted of the following:

• Developed briefing materials for operations, engineering, and management personnel which thoroughly explained the purposes of and differences between the operability determination/evaluation process and the operational decision making process;

• Developed briefing materials which emphasized that the operability determination/evaluation process was to be used not only for safety-related equipment, but also for non-safety related equipment which supported safety-related equipment and non-safety related equipment discussed in the Updated Final Safety Analysis Report;

• Performed an operability determination on the degraded feedwater heater shells; and

• Initiated another issue report to ensure that the other turbine control valve fast acting solenoid functions remained operable.

4OA4 Cross-Cutting Aspects of Findings

A finding discussed in Section 4OA2.2 of this report had, as its primary cause, a problem identification and resolution deficiency, in that, the licensee had identified several examples of degraded, non-safety related equipment which was discussed in the Updated Final Safety Analysis Report. However, the licensee had not recognized the need to perform an operability determination or evaluation for each piece of equipment.

In addition, the licensee had completed other non-corrective action program documentation which provided more information regarding corrective actions and operability impacts than what was included in the associated issue reports.

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000254/2004009-05: Review of On-line Risk Assessment

of Compensatory Actions Taken in Response to a Pinhole Leak.

Introduction:

In following up on a previously identified unresolved item associated with the licensees actions in response to an emergent work condition, the NRC identified a NCV of 10 CFR 50.65(a)(4). Specifically, the NRC identified that the licensee non-conservatively evaluated the on-line risk associated with actions taken in response to an emergent residual heat removal service water leak on January 14, 2003.

Description:

On January 14, 2003, the licensee discovered a pinhole leak in the Unit 1, Train B, residual heat removal service water piping downstream of the residual heat removal heat exchanger. The leak was in an expander just downstream of the normally closed heat exchanger outlet valve, 1-1001-5B. In order to isolate the leak, at 3:29 a.m.,

the licensee closed normally locked open manual valve 1-1001-201B. Upon closing the valve, the licensee declared the system inoperable, but determined that the system was still available and that on-line risk was still Green. However, in order for that train of residual heat removal service water to perform its safety function the manual valve would need to be reopened. At approximately 10:11 a.m., the licensee hung a work tag on the valve, declared the Train B residual heat removal service water system unavailable, and changed the on-line risk to Yellow. The inspectors noted that the on-line risk assessment was contingent upon the status of the residual heat removal service water system. Having one train of residual heat removal service water unavailable by itself increased the site risk above two times normal core damage frequency and changed the on-line risk from Green to Yellow.

Over the 6.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> when Train B residual heat removal service water was considered inoperable but available, the only notification to the operators that the normally locked open manual valve was closed was an entry in the operator logs. No written guidance was provided to alert operators that this closed manual valve would need to be reopened in order for the Train B residual heat removal service water system to perform its safety function. Additionally, no operator was dedicated to ensuring that the valve could be reopened. Also during this time period, a routine shift turnover occurred. The licensee indicated that, to the best of their knowledge, the shift turnover included discussion that the manual valve was closed, and that it would need to be reopened if the system was required; however, this discussion was not documented.

The inspectors reviewed the licensee's work control procedure WC-AA-101.

7 of this procedure contained examples to guide the operators in making determinations as to whether equipment could be declared available. These examples fell into categories including:

• operable equipment;

• inoperable equipment, tagged out of service;

• inoperable equipment due to off-normal alignment during testing with automatic realignment; and

• testing that would require operator action to restore system.

The inspectors noted that none of the examples dealt with emergent conditions where equipment was placed into an abnormal lineup as a compensatory action.

The inspectors determined that the situation most closely resembled either the case of inoperable equipment, tagged out of service, or testing that would require operator action to restore system, because Train B of the system could not perform its safety function without manual action above and beyond normal system initiation from the control room. For both cases, the licensees procedure allowed for equipment to be considered available, if written guidance was provided for restoration.

Analysis:

The inspectors reviewed this issue against the guidance contained in Appendix B, Issue Dispositioning Screening, of Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports. The inspectors concluded that the issue was more than minor since the finding involved a change in on-line risk level from Green to Yellow.

The inspectors reviewed this issue in accordance with Manual Chapter 0609, Significance Determination Process (SDP), Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations. The inspectors determined that the issue was of very low safety significance, or Green, because, although one train of residual heat removal service water was unavailable, the actual safety function of the system could have been performed by the remaining train, the train was not inoperable for greater than the Technical Specification-allowed outage time, and the remaining Phase 1 questions were not applicable.

Enforcement:

Title 10 CFR 50.65(a)(4) requires, in part, that before performing maintenance activities (including but not limited to surveillances, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activity.

Contrary to the above, the licensee failed to perform an adequate risk assessment when the Unit 1 Train B residual heat removal service water system was rendered inoperable and unavailable on January 14, 2003. The failure to perform an adequate risk assessment resulted in the licensee inappropriately assigning an overall Green risk condition for the plant when actual plant conditions warranted a Yellow risk assessment.

Because the failure to adequately assess on-line risk is of very low safety significance and has been entered into the corrective action program as Issue Report 304538, this violation is being treated as a Non-Cited Violation, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000254/2005002-04). Corrective actions for this issue including providing training to operations personnel which focused on crediting manual actions in place of automatic actions as part of a risk assessment.

4OA6 Meetings

.1 Exit Meeting

The inspectors presented the inspection results to Mr. T. Tulon and other members of licensee management at the conclusion of the inspection on April 5, 2005. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit Meetings

Interim exits were conducted for:

• Emergency Preparedness inspection with Mr. T. Tulon on February 11, 2005.

• Closure of Unresolved Item 05000254/2004009-05 with Mr. T. Scott and Mr. W. Beck on February 22, 2005.

4OA7 Licensee-Identified Violations

The following violations of very low significance were identified by the licensee and are violations of NRC requirements which met the criteria of Section VI of the NRC Enforcement Manual, Nuclear Regulatory Guide (NUREG)-1600, for being dispositioned as Non-Cited Violations.

Cornerstone: Emergency Preparedness

Title 10 CFR 50.47 (b)

(15) requires, in part, that radiological emergency response training is provided to those who may be called on to assist in an emergency. Table B-1 of the licensees Standardized Emergency Plan required that the minimum on-shift staffing included two radiation protection personnel for in-plant protective actions. In September 2004 emergency preparedness staff based at another of the licensees Illinois nuclear stations identified that this emergency plan commitment was met by one on-shift radiation protection technician and one on-shift chemistry technician. However, the licensee also determined that chemistry technicians training had evolved such that it no longer met all requirements to provide in-plant protection actions.

In early December 2004, the licensee completed an adequate root cause investigation of this concerns possible impact at each of its Illinois nuclear stations. Timely corrective actions included assigning two radiation protection technicians on all back shifts, initiating revision of the standardized emergency response organization training procedure, and initiating an assessment of emergency response organization position qualifications in cases where some emergency response organization training was being performed by other departments. Longer-term actions included provisions for an effectiveness review of measures taken to ensure that two qualified radiation protection technicians were always on-shift. Because no emergencies had occurred that required in-plant protective actions and the licensees timely corrective actions included staffing a minimum of two radiation protection technicians on-shift, this violation is not more than of very low significance, and is being treated as a NCV.

Cornerstone: Mitigating Systems

Title 10 CFR 50.9 requires, in part, that information required by the Commissions regulations, orders, or license conditions to be maintained by the licensee shall be complete and accurate in all material respects.

Technical Specification 5.4, Procedures, required, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978.

Regulatory Guide 1.33, Appendix A, Section 8, required, in part, that procedures of a type appropriate to the circumstances should be provided to ensure that tools, gauges, instruments, controls, and other measuring and testing devices are properly controlled, calibrated, and adjusted at specified periods to maintain accuracy.

Quad Cities Procedure MA-AA-716-100, Maintenance Alterations Process, Revision 1, Section 4.2.2, required, in part, that if applicable, indicate whether an alteration or restoration verification is required by identifying the type of verification required CV, IV, or N/A.

Maintenance Alteration Logs for torus temperature indicators, residual heat removal suction and discharge pressure indicators, residual heat removal service water pump discharge indicators, and secondary containment differential pressure indicators required either concurrent or independent verifications to be performed after alteration and restoration of the instruments.

Contrary to the above, from January 28 to April 16, 2003, two instrument maintenance technicians at Quad Cities failed to perform required concurrent or independent verification while calibrating the torus temperature indicators, residual heat removal suction and discharge pressure indicators, residual heat removal service water pump discharge indicators, and secondary containment differential pressure indicators in accordance with the associated Maintenance Alterations Logs.

Additionally, the two technicians documented on the Maintenance Alteration Logs that the required concurrent or independent verifications had been completed by another technician. This information is material to the NRC because it demonstrated compliance with the Commissions regulations and procedures of the Quad Cities Nuclear Power Station.

The NRC Office of Investigation investigated the matter and concluded that the individual deliberately falsified Maintenance Alteration Logs. Since the incident was determined to be a deliberate violation of NRC requirements, the violation was subject to the traditional enforcement process instead of the NRCs Significance Determination Process. The violation was categorized in accordance with the NRCs Enforcement Policy at Severity Level IV. On February 28, 2005, after considering the circumstances of the case and after consulting with the Director, Office of Enforcement, this violation was treated as a Non-Cited Violation (ADAMS Accession No. ML050600140), consistent with Section VI.A.1.d of the NRCs Enforcement Policy.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Tulon, Site Vice President

R. Gideon, Plant Manager

R. Armitage, Training Manager

D. Barker, Work Control Manager

W. Beck, Regulatory Assurance Manager

T. Hanley, Maintenance Manager

W. Harris, Emergency Preparedness Manager

D. Hieggelke, Nuclear Oversight Manager

K. Moser, Deputy Engineering Manager

V. Neels, Chemistry/Environ/Radwaste Manager

K. Ohr, Radiation Protection Manager

M. Perito, Operations Manager

A. Scott, Operations

Nuclear Regulatory Commission

M. Ring, Chief, Reactor Projects Branch 1

L. Rossbach, Project Manager, NRR

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000254/2005002-01 URI Inadequate Classification of Modifications

05000265/2005002-01 (Section 1R17)

05000254/2005002-02 URI Drywell Floor Drain Sump Pump 1B Degraded

05000265/2005002-02 (Section 4OA2.2)

05000254/2005002-03 FIN Failure to Initiate Operability Determinations or

05000265/2005002-03 Evaluations When Required (Section 4OA2.2)

05000254/2005002-04 NCV Review of On-Line Risk Assessment of Compensatory Actions Taken in Response to a Pinhole Leak (Section 4OA5)

Closed

05000254/2005002-03 FIN Failure to Initiate Operability Determinations or

05000265/2005002-03 Evaluations When Required (Section 4OA2.2)

05000254/2005002-04 NCV Review of On-Line Risk Assessment of Compensatory Actions Taken in Response to a Pinhole Leak (Section 4OA5)

05000254/2004009-05 URI Review of On-Line Risk Assessment of Compensatory Actions Taken in Response to a Pinhole Leak (Section 4OA5)