IR 05000254/2001017

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IR 05000254/2001-017, IR 05000265/2001-017, Exelon Nuclear, Quad Cities Nuclear Power Station, Units 1 and 2, Inspection on 11/14-12/29/2001 Re Nonroutine Evolutions. One Noncited Violation Noted
ML020150577
Person / Time
Site: Quad Cities  Constellation icon.png
Issue date: 01/15/2002
From: Ring M
Division Reactor Projects III
To: Kingsley O
Exelon Generation Co, Exelon Nuclear
References
IR-01-017
Download: ML020150577 (27)
v • d • e


Text

ary 15, 2002

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION NRC INTEGRATED INSPECTION REPORT 50-254/01-17; 50-265/01-17

Dear Mr. Kingsley:

On December 29, 2001, the NRC completed an inspection at your Quad Cities Units 1 and 2 reactor facilities. The enclosed report documents the inspection findings which were discussed on January 8, 2002, with Mr. Tulon and other members of your staff.

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

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

Based on the results of this inspection, the inspectors identified one issue of very low safety significance (Green). This issue has been entered into your corrective action program and corrective actions have been taken, or are in progress, to prevent recurrence.

In accordance with 10 CFR 2.790 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 50-254/01-17, 50-265/01-17 See Attached Distribution

DOCUMENT NAME: G:\quad\qua2001017 drp.rpt.wpd To receive a copy of this document, indicate in the box:"C" = Copy without enclosure "E"= Copy with enclosure"N"= No copy OFFICE RIII RIII NAME Pelke/trn Ring DATE 01/11/02 01/15/02 OFFICIAL RECORD COPY

REGION III==

Docket Nos: 50-254; 50-265 License Nos: DPR-29; DPR-30 Report No: 50-254/01-17; 50-265/01-17 Licensee: Exelon Nuclear Facility: Quad Cities Nuclear Power Station, Units 1 and 2 Location: 22710 206th Avenue North Cordova, IL 61242 Dates: November 16 through December 29, 2001 Inspectors: K. Stoedter, Senior Resident Inspector J. Adams, Resident Inspector T. Madeda, Regional Security Inspector D. Pelton, Senior Operator Licensing Examiner Approved by: Mark Ring, Chief Branch 1 Division of Reactor Projects

SUMMARY OF FINDINGS IR 05000254-01-17, IR 05000265-01-17 on 11/14 - 12/29/2001, Exelon Nuclear, Quad Cities Nuclear Power Station, Units 1 and 2, Nonroutine Evolutions.

The inspection was conducted by resident and regional inspectors. This inspection identified one Green issue which was not subject to enforcement. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply are indicated by No Color or by the severity level of the applicable violation. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described at its Reactor Oversight Process website at http://www.nrc.gov/NRR/OVERSIGHT/index.html.

A. Inspector Identified Findings Cornerstone: Initiating Events Green. On August 2, 2001, Unit 2 experienced a transformer failure, reactor scram, and loss of offsite power. The inspectors determined that a lightning strike in conjunction with age related degradation and inadequate testing of the Unit 2 main power transformer and switchyard protective relaying contributed to the event and resulted in an increase in the initiating event frequency for plant transients and a loss of offsite power.

The inspectors determined the risk significance of this issue to be very low since all remaining mitigating systems were available to mitigate the transformer rupture, reactor scram, and loss of offsite power (Section 1R14).

B. Licensee Identified Findings No findings of significance were identified.

Report Details 1. REACTOR SAFETY Plant Status Unit 1 began the inspection period at full power. On December 15, 2001, the licensee reduced reactor power to approximately 30 percent for approximately 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br /> in order to implement condenser tube leak repairs, clean two hydrogen coolers, and repair a steam leak on the 1B steam jet air ejector. Following this power reduction, Unit 1 operated at or near full power until December 21, 2001, when power was reduced to approximately 60 percent to locate and suppress local neutron flux in the vicinity of a leaking fuel element. The unit returned to full power approximately 52 hours6.018519e-4 days <br />0.0144 hours <br />8.597884e-5 weeks <br />1.9786e-5 months <br /> later where it operated for the remainder of the inspection period.

Unit 2 began the inspection period at full power. On December 9, 2001, the licensee reduced reactor power to approximately 60 percent for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to perform control rod pattern changes and conduct scram time testing. Unit 2 operated at or near full power for the remainder of the inspection period with the exception of minor power reductions to dampen turbine control valve oscillations on the Number 2 turbine control valve.

1R04 Equipment Alignments (71111.04)

a. Inspection Scope The inspectors verified the system alignment of the following mitigating systems during the period:

The inspectors conducted the walkdowns while redundant equipment was out-of-service for maintenance activities. The inspectors verified that the as-found system configuration and operating parameters supported the continued ability of the system to perform its intended functions. The inspectors accomplished the verifications by comparing the as-found configuration of the accessible portions of the listed systems to the configuration specified in the respective Quad Cities operating procedures. The inspectors reviewed design and licensing information and discussed system configuration and performance with licensee personnel.

b. Findings No findings of significance were identified.

1R05 Fire Protection (71111.05)

a. Inspection Scope The inspectors conducted fire protection walkdowns of the Unit 1/2 electrohydraulic control fluid reservoir area (Fire Zone 8.2.6.C) and the Unit 1/2 turbine building closed cooling water area (Fire Zone 8.2.7.C). These zones contained equipment related to the mitigating systems cornerstone. The inspectors verified the proper control of transient combustibles and ignition sources, the material condition of fire detection and suppression systems, the operational lineup of fire detection and suppression systems, the maintenance of fire protection equipment, and the material condition and operational status of fire barriers. The inspectors also discussed issues associated with each fire zone with the fire marshall.

b. Findings No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

Written Examination and Operating Test Results a. Inspection Scope The inspectors reviewed the pass/fail results of individual written tests, operating tests, and simulator operating tests (required to be given per 10 CFR 55.59(a)(2)) administered by the licensee during calendar year 2001.

b. Findings No findings of significance were identified.

1R12 Maintenance Rule Implementation (71111.12)

a. Inspection Scope The inspectors reviewed the following risk significant systems associated with the Initiating Events and Mitigating Systems Cornerstones:

Unit System Maintenance Rule Function 1&2 Residual Heat Removal Service Water Z1000 1 High Pressure Coolant Injection Room Z5711-04 Coolers 1&2 Circulating Water Z4400-01 The inspectors reviewed problems documented in the following condition reports for appropriate disposition with respect to the Maintenance Rule:

  • Q2001-00106 , Trash Rake Cold Weather Problems;

The inspectors reviewed the licensees implementation of the maintenance rule, including a review of scoping, performance criteria, performance monitoring, expert panel meeting minutes, short-term and long-term corrective actions, and current equipment performance status. The inspectors discussed system problems and maintenance rule classifications with engineering personnel.

b. Findings No findings of significance were identified.

1R13 Maintenance Risk and Emergent Work (71111.13)

a. Inspection Scope The inspectors evaluated risk considerations for planned and emergent work on the following systems:

The inspectors assessed the operability of redundant train equipment and verified that the licensees planning of the maintenance activities minimized the length of time that the plant was subject to increased risk. The inspectors interviewed operations and work control department personnel to ensure that risk of the planned work was assessed in

accordance with Nuclear Station Procedure WC-AA-103, On-Line Maintenance, Revision 4.

b. Findings No findings of significance were identified.

1R14 Nonroutine Plant Evolutions (71111.14)

a. Inspection Scope The inspectors reviewed the licensees submittal of Licensee Event Report 50-265/01-001, Reactor Scram due to Failure of Main Power Transformer, to determine if any operator performance problems contributed to the transformer fire, Unit 2 reactor scram, and loss of offsite power which occurred on August 2, 2001. The inspectors also reviewed Condition Report Q2001-02441, Unit 2 Main Power Transformer Rupture and Loss of Offsite Power, to determine the impact that degraded plant equipment had on the transient and loss of offsite power initiating event frequencies.

b. Findings One Green finding was identified due to age-related degradation and a lack of testing on the Unit 2 main power transformer and the switchyard protective relaying. When combined with a lightning strike, the degraded equipment contributed to an increase in the transient and loss of offsite power initiating event frequencies and resulted in an actual event on August 2, 2001.

The Unit 2 main power transformer was installed in 1993. Since that time, the transformer has been subjected to multiple through-faults and extreme internal forces due to lightning strikes. The transformer design consisted of one bus bar for each phase of alternating current that passed through the transformer. Separation of the bus bars was maintained using bus bar clamps that were bolted to the transformer using fiber bolts. The licensee determined that the vendor had not properly sized the bus bar clamps and that the fiber bolts were not within vendor specified tolerances. Due to these vendor design deficiencies, the strength of the Unit 2 transformers bus bar support system degraded during each through-fault condition due to the forces exerted on the transformer. On August 2, the bus bar support system was degraded to the point that phase-to-phase contact of the bus bars occurred following the lightning strike. This resulted in the transformer rupture. Contributing causes of the transformer failure included the vulnerability of specific offsite power lines to lightning strikes and the lack of a rigorous monitoring plan to implement internal transformer inspections following excessive through-faults.

The licensee determined that the loss of offsite power was caused by the age-related degradation of a transistor in the protective relaying for switchyard breaker 9-10. Each switchyard breaker at Quad Cities was designed with protective relaying to protect plant equipment from electrical faults. Shortly after the lightning strike, a separate disturbance was experienced on offsite power Line 0402 which actuated the protective relaying for

switchyard breaker 9-10. When the protective relaying actuated, a time delay started to allow breaker 9-10 to open. The protective relaying was designed so that if breaker 9-10 opened the time delay would reset. If breaker 9-10 remained closed, open signals were sent to the breakers on each side of breaker 9-10 to isolate the electrical fault (breakers 8-9 and 10-11 in this case). Following the actuation of the protective relaying for breaker 9-10 on August 2, the breaker opened as expected. However, a degraded transistor in the protective relaying circuitry resulted in the reset of the time delay taking longer than expected. As a result, the breakers on each side of breaker 9-10 were provided with open signals which resulted in the loss of offsite power to Unit 2. The licensee determined that the lightning strike on offsite Line 0401, the transformer failure, the disturbance on offsite Line 0402, and the failure to include monitoring of the protective relaying time delay reset function in the preventive maintenance program, contributed to the loss of offsite power.

The inspectors reviewed the risk significance of this issue and determined that the degradation and lack of testing on the main power transformer and the switchyard protective relaying were more than minor because the degradations had an actual impact on safety and contributed to the causes of an initiating event. The inspectors screened the issue using the Significance Determination Process and determined the risk significance of this issue to be very low (Green) since the all remaining mitigating systems were available to mitigate the transformer failure, the reactor scram, and the loss of offsite power (FIN 05-265/01-017-01). No violations of NRC requirements were identified since the equipment degradation and inadequate testing were experienced on non-safety-related equipment.

1R15 Operability Evaluations (71111.15)

.1 Lifting of Standby Liquid Control Relief Valves During Anticipated Transients Without Scram a. Inspection Scope The inspectors reviewed the operability evaluation performed for Condition Report Q2001-02901, Extended Power Uprate Analysis Discovers Potential to Lift Standby Liquid Control Pump Discharge Relief Valves During ATWS [Anticipated Transient Without Scram] Transient, to determine the impact that the prematurely lifting relief valves had on system operability and compliance with 10 CFR 50.62.

b. Findings Background The standby liquid control system was part of the original plant design and provided an independent and diverse method for shutting down the reactor when an insertion of the control rods did not occur. The standby liquid control system shuts down the reactor by pumping a neutron absorbing solution that is capable of achieving and maintaining sub-criticality into the reactor vessel. Although the standby liquid control system contains two pumps, only one pump was needed to perform the initial design basis function.

In 1984, the NRC issued the ATWS rule (10 CFR 50.62). This rule implemented more stringent pump flow rates for the standby liquid control pumps. Specifically, paragraph (c)(4) of 10 CFR 50.62 requires, in part, that each boiling water reactor must have a standby liquid control system with the capability of injecting into the reactor vessel a borated water solution at such a flow rate that the resulting reactivity control was at least equivalent to that resulting from the injection of 86 gallons per minute (gpm) of 13 weight percent sodium pentaborate decahydrate (boron) solution.

Compliance with the ATWS rule To achieve compliance with the ATWS rule, licensee personnel used the methodology provided in General Electric Topical Report NEDE-31096-P-A to determine the required SLC pump flow rate and boron concentration. The results of a calculation provided in the topical report showed that two pump operation was needed in order to provide 80 gpm of at least 14 weight percent sodium pentaborate decahydrate solution to the reactor vessel. The pump flow rate and boron concentration were reviewed and approved by the NRC in Technical Specification safety evaluation reports dated on or before March 28, 1988. The licensee performed calculation QDC-1100-M-0379 and determined that a standby liquid control system pump discharge pressure of 1355 pounds per square inch gauge (psig) was required to ensure that the boron solution was injected into the reactor vessel. This calculation also assumed a reactor vessel dome pressure of 1135 psig which was consistent with General Electrics ATWS analyses NEDE-25026 and NEDE-24223 performed in the 1970's. Both NEDE documents assumed that reactor pressure had stabilized due to actuation of the safety relief valves at the time that the standby liquid control system was initiated. The NEDE documents also used simplified generic main steam relief and safety valve models rather than plant specific models.

During preparations for power uprate implementation, ATWS conditions were re-analyzed using the ODYN computer code approved by the NRC. The ODYN computer code used plant specific main steam relief and safety valve flow capacity and setpoint information. When the plant specific information was inputted into the ODYN code, the licensee determined that reactor vessel pressure could be as high as 1263 psig rather than the 1135 psig calculated in the original ATWS analyses. When the standby liquid control system head losses of 220 psig were added to the newly calculated reactor vessel pressure of 1263 psig, it resulted in a standby liquid control pump discharge pressure of 1483 psig. This new pump discharge pressure was higher than the lowest possible standby liquid control system relief valve setting and would have resulted in the relief valves lifting during system operation. The lifting of the relief valves would cause standby liquid control system flow to be recirculated to the system storage tank rather than injected into the reactor vessel. Due to the inability to provide a continuous 80 gpm of standby liquid control system flow into the reactor vessel as stated by the ATWS rule, the licensees continued compliance with the rule was in question.

Review of Technical Specification Operability Technical Specification Bases Section B 3.1.7 states that the standby liquid control system satisfied the requirements of 10 CFR 50.62 on anticipated transient without scram. Technical Specification Section 3.1.7 required both standby liquid control subsystems to be operable in plant operating Modes 1 and 2. Section 3.1.7 also

described the conditions for operability, the actions required if the operability conditions were not met, and the time allotted to restore the system to operability. Compliance with Technical Specification Surveillance Requirements 3.1.7.1, .2, .3, and .5 ensured that the licensee maintained the required amount of sodium pentaborate solution at the appropriate concentration and temperature. The concentration specified in the Technical Specification Surveillance Requirements was based on the requirements of 10 CFR 50.62 and the ability of the standby liquid control system to inject the sodium pentaborate decahydrate solution into the reactor at a rate of 80 gpm.

Technical Specification Surveillance Requirement 3.1.7.7 required the licensee to demonstrate that each standby liquid control pump was capable of pumping at a rate of at least 40 gpm with a discharge pressure of greater than or equal to 1275 psig. The inspectors reviewed additional information on the lifting relief valves and determined that due to differences in system head losses during one and two pump system operation, the licensee could perform the testing specified in Technical Specification Surveillance Requirement 3.1.7.7 without lifting the relief valves since only one pump was tested at a time. Based upon the continued ability to satisfy Technical Specification Surveillance Requirement 3.1.7.7, the licensee determined the standby liquid control system remained operable even though the licensee was unable to continuously inject 80 gpm of sodium pentaborate solution as required by 10 CFR 50.62.

The inspectors discussed the licensees decision regarding continued standby liquid control system operability with licensee personnel. The licensee maintained that the standby liquid control system remained operable per the Technical Specifications even though the relief valves would lift during two pump operation for the following reasons:

  • Technical Specification Surveillance Requirements were put in place to demonstrate the systems continued ability to perform its safety/design basis function. According to the licensee, the design basis function of the standby liquid control system was to provide an independent and diverse method for shutting down the reactor when an insertion of the control rods did not occur using one standby liquid control pump.
  • The original design basis for the standby liquid control system did not specify a required flow rate or sodium pentaborate decahydrate concentration.
  • The requirements of 10 CFR 50.62 were beyond the design basis of the plant.
  • There was no relationship between the standby liquid control Technical Specification Surveillance Requirements and the ability to demonstrate continued compliance with 10 CFR 50.62.

Through a review of the safety evaluation reports for Technical Specification Amendments 106 (Unit 1) and 93 (Unit 2), the inspectors became aware of a possible relationship between Technical Specification Surveillance Requirement 3.1.7.7 and compliance with 10 CFR 50.62. The safety evaluations stated, the proposal to periodically test only one SLC pump at a time instead of both pumps simultaneously is also acceptable. This is based upon the licensees performance of initial two-pump tests, correlation of single pump data to the initial two-pump data, and subsequent comparison

of the periodic single pump test data to the initial test data for verification of system operability. The inspectors determined that this information directly conflicted with previous information provided by the licensee. Due to the conflicting information, the inspectors were unable to determine if the licensees initial operability decision remained valid.

By the conclusion of the inspection period, the inspectors had become aware of a similar issue that occurred at the Susquehanna plant which also involved conflicting information regarding the relationship between Technical Specifications and 10 CFR 50.62. The Susquehanna issue was the subject of a Region I Task Interface Agreement which was under review by the Office of Nuclear Reactor Regulation. Due to the ongoing review by the Office of Nuclear Reactor Regulation, issues regarding the licensees compliance with 10 CFR 50.62 during relief valve lifting and standby liquid control system operability per the Technical Specifications is considered an unresolved item (URI 50-254/01-17-02; 50-265/01-17-02). The licensee planned to modify both standby liquid control systems during the upcoming refueling outages to eliminate the lifting of the relief valves during two pump operation.

.2 Other Operability Evaluation Reviews a. Inspection Scope The inspectors reviewed the operability evaluations associated with the failure of a fan bearing on the 2A residual heat removal room cooler, the emergency diesel generators fuel oil transfer system day tank admission solenoid valves, and a failure of the 2A residual heat removal room cooler alternate power supply contactor. A list of the documents reviewed by the inspectors can be found in the List of Documents Reviewed section of this report.

The inspectors verified that operability evaluations were performed when required and that completed evaluations were technically adequate, justified continued operation, considered other degraded conditions where applicable, and referenced applicable sections of the Updated Final Safety Analysis Report and other design basis documents.

b. Findings No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17)

a. Inspection Scope The inspectors reviewed the installation of a permanent plant modification on the Unit 1 fuel pool level switch. The modification replaced the existing level switch that was unreliable and no longer supported by the manufacturer.

The inspectors verified that modification preparation, staging, and implementation did not impair the ability to complete plant emergency and abnormal operating procedure actions

if required, monitor key safety functions, or respond to a loss of key safety functions.

The inspectors reviewed the design adequacy of the modification by verifying the following:

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

The inspectors also 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 discussed the modification with station operators, electrical maintenance, and engineering personnel.

b. Findings No findings of significance were identified.

1R19 Post Maintenance Testing (71111.19)

a. Inspection Scope The inspectors reviewed the post-maintenance test data for the following activities associated with Mitigating Systems Cornerstone equipment:

+ Work Order 9909205001, 2-1301-53 Motor Operated Valve Grease Inspection and Stem Lubrication;

The inspectors verified that the post-maintenance tests demonstrated that the systems and components were capable of performing their intended function. Included in the review were the applicable sections of Technical Specifications, the Updated Final Safety Analysis Report, and vendor manuals. Following completion of the tests, the inspectors verified that applicable test equipment was removed and that the equipment was returned to the proper configuration.

b. Findings No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope The inspectors observed surveillance testing activities and/or reviewed completed packages for the tests listed below related to systems in the Mitigating Systems Cornerstone:

  • QCOS 6600-06, Unit 2 Diesel Generator Cooling Water Pump Flow Rate Test, Revision 20, on November 16, 2001;
  • QCOS 6900-02, Station Safety Related Battery Quarterly Surveillance, Revision 14, on November 28, 2001;

The inspectors verified that Technical Specifications, Updated Final Safety Analysis Report, and licensees procedure requirements were met during each testing evolution.

Vibration and valve timing results were compared against In-Service Testing requirements for those components subject to the program. The inspectors also verified that the testing demonstrated that the structure, system, or component was capable of performing its intended function.

b. Findings No findings of significance were identified.

1R23 Temporary Modifications (71111.23)

a. Inspection Scope The inspectors reviewed the temporary modification relocating the toxic gas analyzer flow switch FS7 and removing the auto zero pump, and the associated 10 CFR 50.59 screening. The inspectors compared the contents of these documents against system design basis information including the Updated Final Safety Analysis Report, Technical Specifications, and the Technical Requirements Manual.

The inspectors performed a walkdown of the temporary modification installation verifying consistency with the modification documents and appropriate control of the plant configuration. The inspectors reviewed the testing of the modification, observed installed

sample flow and pressure instrumentation during system operation, and observed the status of toxic gas analyzer annunciators to insure proper operation. The inspectors discussed the performance of the toxic gas analyzer with operators several days after initial installation to verify that the modification performed as expected.

b. Findings No findings of significance were identified.

Emergency Preparedness (EP)

1EP6 Drill Evaluation (71114.06)

a. Inspection Scope The inspectors observed the off-year emergency preparedness exercise conducted on December 18, 2001, which provided opportunities that contributed to the Drill/Exercise Performance Indicator and the Emergency Response Organization Drill Participation Performance Indicator. The scenario involved a lightning strike with the loss of a 125 Volt direct current (Vdc) bus and all control room annunciators, fuel damage due to an abnormal core power distribution, and a release due to a steam leak and the loss of the fuel cladding. The inspectors observed or reviewed the event classifications, event notifications, and the licensees critique of the exercise. The protective action recommendation developed by the emergency operations facility, and the associated notification, were reviewed for accuracy and timeliness. The inspectors also reviewed the following condition reports:

  • Condition Report 00087425, Assembly and Accountability Drill Rated Unsatisfactory;
  • Condition Report 00087526, Emergency Response Organization Augmentation Using Quad Cities Only Failed to Work; and

b. Findings No findings of significance were identified.

3. SAFEGUARDS Physical Protection (PP)

3PP4 Security Plan Changes (71130.04)

a. Inspection Scope The inspector reviewed Revision 53 to the Quad Cities Nuclear Power Station Security Plan and Security Personnel Training and Qualification Plan to verify that the changes

did not decrease the effectiveness of the submitted documents. The referenced revision was submitted in accordance with 10 CFR 50.54(p)(2) requirements by licensee letter dated June 25, 2001.

b. Findings No findings of significance were identified.

4. OTHER ACTIVITIES (OA)

4OA3 Event Follow-up (71153)

a. Inspection Scope The inspectors performed an onsite review of records to evaluate root causes and corrective actions for issues identified in licensee event reports discussed in the Findings Section below. The inspectors evaluated the timeliness, completeness, and adequacy of corrective actions in accordance with the requirements of 10 CFR Part 50, Appendix B, Criterion XVI.

b. Findings (Closed) Licensee Event Report 50-265/00-003-01: Movement of Fuel with Fewer Intermediate Range Neutron Monitors Operable than Required by Technical Specifications. This licensee event report was supplemented to correct information provided in a previous report. The inspectors reviewed the new information and determined that the information did not impact the NRCs initial review of this issue and did not hamper the licensees ability to complete their corrective actions.

(Closed) Licensee Event Report 50-265/01-001: Reactor Scram due to Transformer Failure. This issue was discussed in Section 1R14 of this inspection report. One Green finding was identified. The inspectors have reviewed the licensees corrective actions and found them to be appropriate. This event did not constitute a violation of NRC requirements. No other issues were identified.

4OA5 Other Review of World Association of Nuclear Operators Peer Review Report On November 28, 2001, the inspectors completed a review of the World Association of Nuclear Operators Peer Review Report for Quad Cities Station which was issued on September 28, 2001. The peer review was conducted July 23 through 30, 2001, and was similar to the plant evaluations performed by the Institute of Nuclear Power Operations. The inspectors determined that no new safety or training issues were identified in the report which were previously unknown to the NRC. No additional follow-up inspections are planned to address items contained in the report.

4OA6 Meetings

.1 Management Meeting Held On December 6, 2001, Messrs. James Caldwell, Geoff Grant, Jack Grobe, and Mark Ring visited the Quad Cities site to participate in a management meeting with Exelon senior management. Topics discussed during the meeting included current plant performance, areas for improvement, and the resolution of current communication issues between Exelon and the NRC. The residents provided NRC management with a site tour.

.2 Inspection Period Exit Meeting The inspectors presented the inspection results to Mr. Tulon and other members of licensee management at the conclusion of the inspection on January 8, 2002. The licensee acknowledged the findings presented. No proprietary information was identified.

.3 Interim Exit Meeting Senior Official at Exit: K. Leech, Security Manager Date: July 2, 2001 Proprietary Information: No Subject: Review of Security Plan Revision

.4 Interim Exit Meeting Senior Official at Exit: Joe White, Operations Training Manager Date: November 29, 2001 Proprietary No Subject: Results of Licensed Operator Requalification Testing for Calender Year 2001 and Applicability of NRC Inspection Manual Chapter 0609, Appendix I, Operator Requalification Human Performance Significance Determination Process (SDP)

Change to Inspection Findings: No

PARTIAL LIST OF PERSONS CONTACTED Licensee T. Tulon, Site Vice President G. Barnes, Plant Manager R. Armitage, Training Manager D. Barker, Radiation Protection Manager W. Beck, Regulatory Assurance Manager G. Boerschig, Engineering Manager R. Chrzanowski, Nuclear Oversight Manager R. Gideon, Work Control Manager K. Leech, Security Manager M. McDowell, Operations Manager K. Moser, Chemistry/Environ/Radwaste Manager M. Perito, Maintenance Manager NRC M. Ring, Chief, Reactor Projects Branch 1 ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-265/01-17-01 FIN Degraded and inadequately tested transformer and protective relaying results in increase in transient and loss of offsite power initiating event frequencies.

50-254/01-17-02; 50-265/01-17-02 URI Relief valves lift during two pump operation required by 10 CFR 50.62.

Closed 50-265/01-17-01 FIN Degraded and inadequately tested transformer and protective relaying results in increase in transient and loss of offsite power initiating event frequencies.

50-265/00-003-01 LER Movement of Fuel with Fewer Intermediate Range Neutron Monitors Operable than Required by Technical Specifications.

50-265/01-001 LER Reactor Scram due to Transformer Failure.

LIST OF ACRONYMS AND INITIALISMS USED ATWS Anticipated Transient Without Scram CFR Code of Federal Regulations DRP Division of Reactor Projects EP Emergency Preparedness FIN Finding gpm gallons per minute LER Licensee Event Report OA Other Activities PARS Publically Available Records System PP Physical Protection psig pounds per square inch gauge SDP Significance Determination Process URI Unresolved Item Vdc Volt direct current

LIST OF DOCUMENTS REVIEWED 1R04 Equipment Alignment Number Subject/Title Date/Revision QCOP 1400-01 Core Spray System Preparation for Standby Revision 13 Operation QCOP 2900-01 Safe Shutdown Makeup Pump System Revision 16 Preparation for Standby Operation QCOP 2300-01 High Pressure Coolant Injection System Revision 29 Preparation for Standby Operation QCOP 1000-02 Residual Heat Removal System Preparation Revision 16 for Standby Operation QCOP 1000-04 Residual Heat Removal System Service Water Revision 14 System Operation 1R12 Maintenance Rule Implementation Number Subject/Title Date/Revision Q2001-00296 2A Residual Heat Removal Heat Exchanger January 27, 2001 Degraded When Reversing Valve Failed to Reposition Q2001-00106 Trash Rake Cold Weather Problems January 11, 2001 Q2000-02202 Backup High Pressure Coolant Injection Room June 15, 2000 Cooler Service Water Check Valve Failure Q2001-01861 High Pressure Coolant Injection Area Cooler June 13, 2001 Fan Trip Alarm Q2001-02531 Unit 1 High Pressure Coolant Injection Room August 11, 2001 Cooler Supply Check Valve 1R13 Maintenance Risk and Emergent Work Number Subject/Title Date/Revision NSP WC-AA-103 On-Line Maintenance Revision 4 QC-PSA-006 Quad Cities Nuclear Power Station Units 1 and October 13 2 Dependency Matrix

BSA-Q-96-01 Quad Cities ECCS Pump Room Thermal Revision 1 Response To Loss of Room Cooler BSA-Q-97-04 Quad Cities ECCS Pump Room Thermal Revision 4 Response To Loss of Room Cooler Under Appendix R Assumptions Action Request # 1A Core Spray/ Reactor Core Isolation Cooling December 10, 00085777 Pump Room Cooler Fan Belt Broken 2001 1R14 Non-Routine Evolutions Number Subject/Title Date/Revision LER 50-265/01-001 Reactor Scram due to Failure of Main Power October 1, 2001 Transformer Condition Report # Unit 2 Main Power Transformer Rupture and August 2, 2001 Q2001-02441 Loss of Offsite Power 1R15 Operability Evaluations Number Subject/Title Date/Revision Condition Report # EPU Analysis Discovers Potential to Lift SBLC Q2001-02901 Pump Discharge Relief Valves During ATWS Transient Supporting Operability SLC System May Not Meet the Requirements September 21, Evaluation for of 10 CFR 50.62 due to Lifting of Pump 2001 Condition Report Discharge Relief Valves Q2001-02901 NRC Information Inadequate Standby Liquid Control System August 10, 2001 Notice 2001-13 Relief Valve Margin MPA A-20 and TACS Plant Specific ATWS Review Guidelines and January 27, 1987 59132 and 59133 Implementation Schedule Amendment Request for Unit 1 Standby Liquid November 17, Control System 1987 Amendment Request for Unit 2 Standby Liquid October 28, 1986 Control System Amendment 106 Safety Evaluation Report March 28, 1988 Amendment 93 Safety Evaluation Report Unknown

Condition Report # Unit 2 Emergency Diesel Generator Day Tank Q2001-01312 Level Drop Condition Report # Unit 2 Emergency Diesel Generator Day Tank Q2001-01338 Level Drop Condition Report # Quad Cities Operating Procedure 6600-09 Q2001-01982 Time Validation Condition Report # Errors in PowerLabs Test Report Concerning Q2001-02518 Emergency Diesel Generator Fuel Oil Solenoid Failure Condition Report # Possible High Differential Pressure Condition Q2001-02659 on Unit 1, Unit 2, and Unit 1/2 Emergency Diesel Generator Fuel Oil Transfer Pump Supporting Operability Determination Documentation for Condition Report Q2001-02659 QCOP 6600-09 Filling of Diesel Generator Fuel Oil Tanks with Revision 4 the Installed System Unavailable HVA274786 Automatic Switch Company Drawing Condition Report 2A Residual Heat Removal Room Cooler November 23,

  1. 83732 Making Cyclical Rubbing Noise 2001 Condition Report 2A Residual Heat Removal Room Cooler November 23,
  1. 83748 Bearing 2001 Supporting Operability 2A Residual Heat Removal Room Cooler Revision 0 Evaluation for Bearing Failure Operability Evaluation Condition Report
  1. 83748 Supporting Operability 2A Residual Heat Removal Room Cooler Revision 1 Evaluation for Bearing Failure Operability Evaluation Condition Report
  1. 83748 Condition Report # Contactor Stuck Shut for the 2A Residual Heat October 2, 2001 Q2001-03053 Removal System Room Cooler Normal Power Supply Condition Report # Failed Post Maintenance Test of A Residual June 14, 1999 Q1999-02022 Heat Removal Room Cooler Alternate Feed Switch

1R17 Permanent Plant Modifications Number Subject/Title Date/Revision Design Change Replacement of the Fuel Pool Level Switch on Revision 0 Package 9900618 Unit 1 50.59 Screening Replacement of the Fuel Pool Level Switch on Revision 0 QC-S-2001-0340 Unit 1 Work Order Package Installation of Unit 1 Fuel Pool Level Switch November 27, 99249765-01 2001 QCOS 1900-02 Fuel Storage Pool Level Alarm Testing Revision 6 1R19 Post Maintenance Testing Number Subject/Title Date/Revision QCOS 1300-07 Reactor Core Isolation Cooling Manual Temporary Initiation Test Change 304 QCOS 0005-04 In-service Testing Valve Position Indication Revision 8 Surveillance (Partial) for 2-1301-53, 2-1301-60, and 2-1301-62 QCOS 1300-06 Reactor Core Isolation Cooling Power Revision 18 Operated Valve Test (Partial) for 2-1301-53, 2-1301-60, and 2-1301-62 QCOS 1300-19 Reactor Core Isolation Cooling Torus Suction Revision 8 Check Valve Closure Test QCOS 1300-17 Reactor Core Isolation Cooling Pump Revision 13 Operability Test Slow Roll After Maintenance QOS 5600-04 Weekly Turbine-Generator Tests Revision 49 1R22 Surveillance Testing Number Subject/Title Date/Revision QCOS 6600-06 Unit 2 Diesel Generator Cooling Water Pump Revision 20 Flow Rate Test QCOS 1000-06 2A Residual Heat Removal Pump/Loop Revision 26 Operability Test QCOS 1000-09 Unit 1 Residual Heat Removal Power Operated Revision 14 Valve Test

QCOS 6900-02 Station Safety Related Battery Quarterly Revision 14 Surveillance QCOS 1300-04 Unit 2 Reactor Core Isolation Cooling Turbine Revision 22 Overspeed Test QCOS 1300-05 Unit 2 Quarterly Reactor Core Isolation Cooling Revision 31 Pump Operability Test 1R23 Temporary Modifications Number Subject/Title Date/Revision Temporary Relocation of Toxic Gas Analyzer Flow Switch Revision 0 Modification Design Flow Switch 7 and Removal of Auto Zero Change Package Pump 333806 QC-S-2001-0459 10 CFR 50.59 Screening for the Relocation of Revision 0 Toxic Gas Analyzer Flow Switch Flow Switch 7 and Removal of Auto Zero Pump 22

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