IR 05000254/2010002
| ML101240980 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 05/03/2010 |
| From: | Ring M NRC/RGN-III/DRP/B1 |
| To: | Pardee C Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-10-002 | |
| Download: ML101240980 (38) | |
Text
May 3, 2010
SUBJECT:
QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000254/2010002; 05000265/2010002
Dear Mr. Pardee:
On March 31, 2010, 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 results, which were discussed on April 6, 2010, with Mr. T. 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, no findings of significance were identified.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
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 05000254/2010002; 05000265/2010002 w/Attachment: Supplemental Information
REGION III==
Docket Nos: 50-254, 50-265 License Nos: DPR-29, DPR-30 Report No: 05000254/2010002 and 05000265/2010002 Licensee: Exelon Nuclear Facility: Quad Cities Nuclear Power Station, Units 1 and 2 Location: Cordova, IL Dates: January 1 through March 31, 2010 Inspectors: J. McGhee, Senior Resident Inspector B. Cushman, Resident Inspector E. Coffman, Reactor Engineer D. Jones, Inspector, DRS C. Mathews, Illinois Emergency Management Agency Approved by: M. Ring, Chief Branch 1 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000254/2010002, 05000265/2010002; 01/01/10 - 03/31/10; Quad Cities Nuclear Power
Station, Units 1 & 2; Routine Integrated Inspection Report.
This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. 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 4, dated December 2006.
NRC-Identified
and Self-Revealed Findings No findings of significance were identified.
Licensee-Identified Violations
No violations of significance were identified.
REPORT DETAILS
Summary of Plant Status
Unit 1 Unit 1 operated at 100 percent thermal power throughout the evaluated period from January 1 through March 15, 2010, with the exception of planned power reductions for routine surveillances, planned equipment repair, and control rod maneuvers.
On March 16, 2010, a single control inserted automatically (scrammed) on Unit 1 during weekly reactor protection system test switch surveillance testing resulting in a 4 percent power reduction. The rod was appropriately isolated, and thermal power was returned to 100 percent while troubleshooting and repair were performed on the control rod. Power was lowered to 84 percent at 10:00 p.m. on March 20, 2010, to recover the control rod. Following rod repair, recovery and scram time testing, the unit was returned to 100 percent at 1:00 a.m. on March 21.
The unit remained at 100 percent thermal power through March 31, 2010.
Unit 2 Unit 2 operated at full power with the exception of planned power reductions for routine surveillances, planned equipment repair, and control rod maneuvers. Unit 2 operated at 100 percent thermal power throughout the evaluated period from January 1 through February 24, 2010, when the unit began to coast down in power to the refueling outage that began on March 14, 2010. At 12:00 a.m. on March 15, 2010, the unit was shut down for refueling. Refueling outage Q2R20 continued through March 31,
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04 Equipment Alignment
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant systems:
- Unit 1 high pressure coolant injection (HPCI) system with the Unit 1 reactor core isolation cooling system (RCIC) out-of-service for maintenance;
- 1/2 B standby gas treatment system (SBGTS) while relied upon as protected equipment; and
- 1/2 emergency diesel generator while relied upon as protected equipment.
The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Analysis Report (UFSAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable.
The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies.
The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program (CAP) with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.
These activities constituted four partial system walkdown samples as defined in Inspection Procedure (IP) 71111.04-05.
b. Findings
No findings of significance were identified.
.2 Semi-Annual Complete System Walkdown
a. Inspection Scope
During the time period of March 1, 2010, to March 12, 2010, the inspectors performed a complete system alignment inspection of the Unit 2 HPCI system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment.
The inspectors walked down the system to review mechanical and electrical equipment line-ups, electrical power availability, system pressure and temperature indications, component labeling, component lubrication, component and equipment cooling, hangers and supports, and operability of support systems. Inspectors also verified that ancillary equipment, scaffold erection or debris did not interfere with equipment operation.
A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment to this report.
These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.
b. Findings
No findings of significance were identified.
.3 System Walkdown Associated with Temporary Instruction 2515/177, Managing Gas
Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems.
a. Inspection Scope
and Documentation During the time period from March 1, 2010, to March 12, 2010, the inspectors conducted a walkdown of the Unit 2 HPCI system in sufficient detail to reasonably assure the acceptability of the licensees walkdowns (Temporary Instruction [TI] 2515/177, Section 04.02.d). The inspectors also verified that the information obtained during the licensees walkdown was consistent with the items identified during the inspectors independent walkdown (TI 2515/177, Section 04.02.c.3).
In addition, the inspectors verified that the licensee had isometric drawings that describe the Unit 2 HPCI system configuration and had acceptably confirmed the accuracy of the drawings (TI 2515/177, Section 04.02.a). The inspectors verified the following related to the isometric drawings:
- high point vents were identified;
- high points that do not have vents were acceptably recognizable;
- other areas where gas can accumulate and potentially impact subject system operability such as at orifices in horizontal pipes, isolated branch lines, heat exchangers, improperly sloped piping, and under closed valves, were acceptably described in the drawings or in referenced documentation;
- horizontal pipe centerline elevation deviations and pipe slopes in nominally horizontal lines that exceed specified criteria were identified;
- all pipes and fittings were clearly shown; and
- the drawings were up-to-date with respect to recent hardware changes and that any discrepancies between as-built configurations and the drawings were documented and entered into the CAP for resolution.
The inspectors verified that piping and instrumentation diagrams (P&IDs) accurately described the subject system, that they were up-to-date with respect to recent hardware changes, and any discrepancies between as-built configurations, the isometric drawings, and the P&IDs were documented and entered into the CAP for resolution (TI 2515/177, Section 04.02.b).
Documents reviewed are listed in the Attachment to this report.
This inspection effort counts towards the completion of TI 2515/177, which will be closed in a later inspection report.
b. Findings
No findings of significance were identified.
1R05 Fire Protection
.1 Routine Resident Inspector Tours
a. Inspection Scope
The inspectors conducted fire protection walkdowns. which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:
- Service Building Elevation 6230, Control Room, Fire Zone 2.0;
- Service Building Elevation 5950, Computer Room in Auxiliary Electric Room, Fire Zone 4.0;
- Service Building Elevation 5950, Auxiliary Electric Room, Fire Zone 6.3;
- Service Building Elevation 6090, Cable Spreading Room, Fire Zone 3.0; and
- Unit 2 Reactor Building Elevation 5540, Torus Area and Top of Torus, Fire Zone 1.1.2.1.
The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment, which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.
Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.
Documents reviewed are listed in the Attachment to this report.
These activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.
b. Findings
No findings of significance were identified.
1R07 Annual Heat Sink Performance
.1 Heat Sink Performance
a. Inspection Scope
The inspectors reviewed the licensees inspection and post-inspection testing of the Unit 2 emergency diesel generator 2A and 2B cooling water heat exchangers to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspection included independent inspection of the heat exchangers immediately after they were opened for inspection. The inspectors reviewed the licensees observations as compared against acceptance criteria. Documents reviewed for this inspection are listed in the Attachment to this report.
This annual heat sink performance inspection constituted one sample as defined in IP 71111.07-05.
b. Findings
No findings of significance were identified.
1R08 Inservice Inspection Activities
From March 8, 2010, through March 12, 2010, the inspectors conducted a review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the reactor coolant system, risk-significant piping and components, and containment systems.
The inservice inspections described in Sections 1R08.1 and 1R08.2 below constituted one inspection sample as defined in IP 71111.08-05.
.1 Piping Systems Inservice Inspection
a. Inspection Scope
The inspectors observed the following non-destructive examinations mandated by the American Society of Mechanical Engineers (ASME)Section XI Code to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.
- Ultrasonic Examination of the Residual Heat Removal (RHR) Pipe to Elbow Weld, 1008B-7, Report No. Q2R20-012;
- Magnetic Particle Examination of the Emergency Core Cooling System (ECCS)8 Lugs Welded to Pipe 1025-W-212 A, Report No. Q2R20-023.
During the prior outage non-destructive surface and volumetric examinations, the licensee did not identify any relevant/recordable indications. Therefore, no NRC review was completed for this inspection procedure attribute.
The inspectors reviewed the following pressure boundary weld completed for a risk-significant system since the beginning of the last refueling outage to determine if the licensee applied the pre-service non-destructive examinations and acceptance criteria required by ASME Code Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedure was qualified in accordance with the requirements of Construction Code and the ASME Code Section IX:
b. Findings
No findings of significance were identified.
.2 Identification and Resolution of Problems
a. Inspection Scope
The inspectors performed a review of ISI-related problems entered into the licensees corrective action program and conducted interviews with licensee staff to determine if:
- the licensee had established an appropriate threshold for identifying ISI-related problems;
- the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and
- the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.
The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program
.1 Resident Inspector Quarterly Review
a. Inspection Scope
On February 12, 2009, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
- oversight and direction from supervisors; and
- ability to identify and implement appropriate TS actions and emergency plan actions and notifications.
The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.
This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11.
b. Findings
No findings of significance were identified. An observation involving compensatory actions and associated training is discussed in Section 4OA2 of this report.
1R12 Maintenance Effectiveness
.1 Routine Quarterly Evaluations
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk-significant systems:
- Z0202; Recirculation System; and
- Z5704; Reactor Building Heating, Ventilation, and Air Conditioning.
The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:
- implementing appropriate work practices;
- identifying and addressing common cause failures;
- scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
- characterizing system reliability issues for performance;
- charging unavailability for performance;
- trending key parameters for condition monitoring;
- ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
- verifying appropriate performance criteria for structures, systems, and components/functions classified as (a)(2) or appropriate and adequate goals and corrective actions for systems classified as (a)(1).
The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.
This inspection constituted two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
.1 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:
- Work Week 02 (online unit risk evaluation) - 2B service water pump, 1/2 emergency diesel generator (EDG), 1/2 diesel generator cooling water pump rotating element replacement and alignment tolerance issues;
- Work Week 12 (online unit risk evaluation) - Unit 2 electrical bus outages, Unit 2 EDG, Transformer T22 outage, 1/2 A standby gas treatment;
- Unit 2 outage schedule shutdown risk for first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> - unit shutdown, reduced water inventory operations, operation with a potential to drain the reactor vessel (OPDRVs), multiple electrical bus outages, Unit 2 EDG;
- Unit 2 outage schedule shutdown risk for first weekend of outage (March 17-21, 2010) - reactor cavity flooded, fuel shuffle, OPDRVs, multiple electrical bus outages, T22 outage, U2 EDG, 1/2 A standby gas treatment system, 2C/2D residual heat removal pumps, 2C/2D residual heat removal service water pumps;
- Work Week 13 (online unit risk evaluation) and associated schedule changes -
Unit 2 electrical bus outages, Unit 2 EDG, T22 outage, U2 250 Vdc Battery; and
- Work Week 14 (online unit risk evaluation) and associated schedule changes -
abnormal electrical lineup, Unit 2 EDG outage extension, and motor control center 28-1A outage.
These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor when questions were identified, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.
These maintenance risk assessments and emergent work control activities constituted six samples as defined in IP 71111.13-05.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- Issue Report 1010239: Broken phenolic pieces identified to secondary contacts of 2D residual heat removal service water pump supply breaker;
- IR 1021963: Voltage spikes identified for 4kV safety bus supply during troubleshooting activities;
- IR 1018379: Incorrect torque sequence given in work package;
- IR 1029824: HPCI cooling water pump check valve;
- IR 1041420: Safe shutdown makeup pump controller oscillations; and
- IR 1049056: Minor cavitation pitting inside 2-1402-38B.
The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.
This operability inspection constituted six samples as defined in IP 71111.15-05.
b. Findings
No findings of significance were identified.
1R18 Plant Modifications
.1 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the following temporary modification(s):
- TCCP/TIC-2498, Unit 2 Vdc Battery Swap for Foam Replacement.
The inspectors compared the temporary configuration changes and associated 10 CFR 50.59 screening and evaluation information against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors also compared the licensees information to operating experience information to ensure that lessons learned from other utilities had been incorporated into the licensees decision to implement the temporary modification. The inspectors, as applicable, 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. Lastly, the inspectors discussed the temporary modification with operations, engineering, and training personnel to ensure that the individuals were aware of how extended operation with the temporary modification in place could impact overall plant performance. Documents reviewed in the course of this inspection are listed in the Attachment to this report.
This inspection constituted one temporary modification samples as defined in IP 71111.18-05.
b. Findings
No findings of significance were identified.
.2 Permanent Plant Modifications
a. Inspection Scope
The following engineering design package was reviewed, and selected aspects were discussed with engineering personnel:
This document and related documentation were reviewed for adequacy of the associated 10 CFR 50.59 safety evaluation screening, consideration of design parameters, and installation of the field equipment associated with this modification.
The inspectors observed ongoing and completed work activities to verify that installation was consistent with the design control documents. The modification installed ultrasonic feedwater flow instrumentation with improved accuracy for input to the unit heat balance for determination of plant thermal power. The new system includes a flow meter spool piece in each of the three feedwater pump discharge headers. Each spool piece contained 16 ultrasonic flow transducers, a pressure tap, and a temperature sensor.
The pressure and temperature sensors in the spool piece provide for density compensation of the flow measurement. The sensors are divided into two channels powered from different electrical power supplies to provide redundancy and reliability.
Documents reviewed in the course of this inspection are listed in the Attachment to this report.
Because the installation and acceptance testing of this modification continued into the next inspection period, the inspections performed to date constitute a partial performance of a permanent plant modification sample as defined in IP 71111.18-05.
Documentation of the completed sample will be included in a later inspection report.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
.1 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:
- Work Order (WO) 1210011: Replace existing 1/2 diesel generator cooling water pump rotating element;
- WO 1314050: Replace VPRO Module X in 1-1901-31-7 (digital electro-hydraulic control system card replacement); and
- WO 1314563: Unit 2 diesel generator load test.
These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):
the effect of testing on the plant had been adequately addressed, testing was adequate for the maintenance performed, acceptance criteria were clear and demonstrated operational readiness, test instrumentation was appropriate, tests were performed as written in accordance with properly reviewed and approved procedures, equipment was returned to its operational status following testing, and test documentation was properly evaluated. The inspectors evaluated the activities against TS, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted four post-maintenance testing samples as defined in IP 71111.19-05.
b. Findings
No findings of significance were identified.
1R20 Outage Activities
.1 Refueling Outage Activities
a. Inspection Scope
The inspectors reviewed the shutdown safety management plan (SSMP) and contingency plans for the Unit 2 refueling outage conducted March 15 - 31, 2010, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. Additionally, inspectors confirmed planned work schedules conformed to work hour rules put forth in 10 CFR 26 for covered workers.
During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below. Documents reviewed during the inspection are listed in the Attachment to this report.
- Work schedules were reviewed for selected workers in operations, fire brigade, and maintenance covered positions;
- Licensee configuration management, including maintenance of defense-in-depth commensurate with the SSMP for key safety functions and compliance with the applicable TS when taking equipment out-of-service;
- Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing;
- Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and accounting for instrument error;
- Controls over the status and configuration of electrical systems to ensure that TS and SSMP requirements were met, and controls over switchyard activities;
- Monitoring of decay heat removal processes, systems, and components;
- Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system;
- Reactor water inventory controls including flow paths, configurations, alternative means for inventory addition, and controls to prevent inventory loss;
- Controls over activities that could affect reactivity;
- Maintenance of secondary containment as required by TS;
- Refueling activities, including fuel handling and sipping to detect fuel assembly leakage; and
- Licensee identification and resolution of problems related to refueling outage activities.
Since the outage was still in progress at the close of the inspection period, the inspection activities performed during this period constitute a partial completion of one sample for IP 71111.20. Additional inspection activities and document reviews performed to complete the sample will be documented in a later inspection report.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
.1 Surveillance Testing
a. Inspection Scope
The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:
- Fill and Vent Verification Procedures for ECCS Systems (Routine);
- Reactor Coolant Leakage in the Drywell (RCS);
- Diesel Generator Endurance and Margin/Full Load Reject/Hot Restart Test (Routine);
- Unit 1 Reactor Recirculation Pump Runout Limits Determination and Setting (Routine);
- Secondary Containment Capability Test (Routine); and
- RHR Containment Spray Line Isolation B Valve (CIV).
The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:
- did preconditioning occur;
- were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;
- were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis;
- plant equipment calibration was correct, accurate, and properly documented;
- as-left setpoints were within required ranges and the calibration frequency was in accordance with TS, the UFSAR, procedures, and applicable commitments;
- measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy, applicable prerequisites described in the test procedures were satisfied;
- test frequencies met TS requirements to demonstrate operability and reliability, tests were performed in accordance with the test procedures and other applicable procedures, jumpers, and lifted leads were controlled and restored where used;
- test data and results were accurate, complete, within limits, and valid;
- test equipment was removed after testing;
- where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, ASME code, and reference values were consistent with the system design basis;
- prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;
- equipment was returned to a position or status required to support the performance of its safety functions; and
- all problems identified during the testing were appropriately documented and dispositioned in the CAP.
Also, additional activities were performed during the review of Fill and Vent Verification Procedures for ECCS Systems that were associated with TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems. These activities are described in bullet
.2 of this section.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted four routine surveillance testing samples, one inservice testing sample, one reactor coolant system leak detection inspection sample, and one containment isolation valve sample as defined in IP 71111.22, Sections -02 and -05.
b. Findings
No findings of significance were identified.
.2 Fill and Vent Verification Procedures Associated with Temporary Instruction 2515/177,
Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems.
a. Inspection Scope
The inspectors verified that procedures were acceptable for the following systems:
- Units 1&2 HPCI;
- Units 1&2 CS; and
The inspectors reviewed procedures used for conducting surveillances and determination of void volumes to ensure that the void criteria was satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.a). Also, the inspectors reviewed procedures used for filling and venting the following conditions which may have introduced voids into the subject systems to verify that the procedures acceptably addressed testing for such voids and provided acceptable processes for their reduction or elimination (TI 2515/177, Section 04.03.b). Specifically, the inspectors verified that:
- Gas intrusion prevention, refill, venting, monitoring, trending, evaluation, and void correction activities were acceptably controlled by approved operating procedures (TI 2515/177, Section 04.03.c.1);l
- Procedures ensured the system did not contain voids that may jeopardize operability (TI 2515/177, Section 04.03.c.2);
- Procedures established that void criteria were satisfied and will be reasonably ensured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.c.3);
- The licensee entered changes into the CAP as needed to ensure acceptable response to issues (TI 2515/177, Section 04.03.c.5); and
- Procedures included independent verification that critical steps were completed (TI 2515/177, Section 04.03.c.6).
The inspectors verified the following with respect to surveillance and void detection:
- Specified surveillance frequencies were consistent with TS SR requirements (TI 2515/177, Section 04.03.d.1);
- Surveillance frequency determination was described (TI 2515/177, Section 04.03.d.2);
- Surveillance methods were acceptably established to achieve the needed accuracy (TI 2515/177, Section 04.03.d.3);
- Surveillance procedures included up-to-date acceptance criteria (TI 2515/177, Section 04.03.d.4);
- Procedures included effective follow-up actions when acceptance criteria are exceeded or when trending indicated that criteria may be approached before the next scheduled surveillance (TI 2515/177, Section 04.03.d.5);
- Measured void volume uncertainty was considered when test data was compared to acceptance criteria (TI 2515/177, Section 04.03.d.6);
- Venting procedures and practices utilized criteria such as adequate venting durations and observation of a steady stream of water (TI 2515/177, Section 04.03.d.7);
- An effective sequencing of void removal steps was followed to ensure that gas does not move into previously filled system volumes (TI 2515/177, Section 04.03.d.8);
- Qualitative void assessment methods included expectations that the void will be significantly less than allowed by acceptance criteria (TI 2515/177, Section 04.03.d.9);
- Venting results were trended periodically to confirm that the systems are sufficiently full of water and that the venting frequencies are adequate. The inspectors also verified that records on the quantity of gas at each location are maintained and trended as a means of preemptively identifying degrading gas accumulations (TI 2515/177, Section 04.03.d.10);
- Surveillances were conducted at locations where a void could form, including high points, dead legs, and locations under closed valves in vertical pipes (TI 2515/177, Section 04.03.d.11);
- Systems were not pre-conditioned by other procedures that may cause a system to be filled, such as by testing, prior to the void surveillance (TI 2515/177, Section 04.03.d.12); and
- Procedures included gas sampling for unexpected void increases if the source of the void is unknown and sampling is needed to assist in determining the source (TI 2515/177, Section 04.03.d.13).
The inspectors verified the following with respect to filling and venting:
- Revisions to fill and vent procedures to address new vents or different venting sequences were acceptably accomplished (TI 2515/177, Section 04.03.e.1);
- Fill and vent procedures provided instructions to modify restoration guidance to address changes in maintenance work scope or to reflect different boundaries from those assumed in the procedure (TI 2515/177, Section 04.03.e.2); and
- Void removal methods were acceptably addressed by approved procedures (TI 2515/177, Section 04.03.f.1).
Documents reviewed are listed in the Attachment to this report.
This inspection effort counts towards the completion of TI 2515/177, which will be closed in a later inspection report.
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine licensee emergency drill on February 18, 2010, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.
This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1 Unplanned Scrams per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours performance indicator (PI) for Quad Cities Units 1 and 2 for the period from the 1st quarter 2009 through the 4th quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC Inspection Reports for the period of January 2009 through December 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator, and none were identified.
This inspection constituted two unplanned scrams per 7000 critical hours samples as defined in IP 71151-05.
b. Findings
No findings of significance were identified.
.2 Unplanned Scrams with Complications
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams with Complications performance indicator for Quad Cities Units 1 and 2 for the period from the 1st quarter 2009 through the 4th quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC Integrated Inspection Reports for the period of January 2009 through December 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator, and none were identified.
This inspection constituted two unplanned scrams with complications samples as defined in IP 71151-05.
b. Findings
No findings of significance were identified.
.3 Unplanned Transients per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Transients per 7000 Critical Hours performance indicator for Quad Cities Units 1 and 2 for the period from the 1st quarter 2009 through the 4th quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC Integrated Inspection Reports for the period of January 2009 through December 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator, and none were identified.
This inspection constituted two unplanned transients per 7000 critical hours samples as defined in IP 71151-05.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection
.1 Routine Review of Items Entered into the Corrective Action Program
a. Inspection Scope
As part of the various baseline inspection procedures 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 CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: the complete and accurate identification of the problem; that timeliness was commensurate with the safety significance; that evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.
Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the attached List of Documents Reviewed.
These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.
b. Findings
/Observations No findings of significance were identified. However, the inspectors identified examples of insufficient rigor in implementation of interim corrective actions or compensatory measures for degraded plant equipment that occurred in 2009 and in February and March of 2010. Although these examples did not individually result in sufficient impact to prevent the accomplishment of the required activity, the lack of rigor in implementing the action could very well have delayed personnel from taking the required actions or have otherwise challenged emergency response. Specific examples are discussed below:
- On August 12, 2009, the NRC inspectors raised questions concerning operability of systems where in-progress work activities had defeated a flood protection barrier (documented in Inspection Report 05000254/2009004). The licensee provided interim guidance to the operating staff in the form of a standing order that identified actions necessary to maintain system operability with an impaired flood barrier. While the on-shift crew took appropriately conservative actions, a different crew later that day did not correctly apply the standing order and failed to implement the compensatory actions required to maintain operability of the affected system. Subsequent revision of the implementing procedure and just-in-time training provided clarification of the issue.
- Issue Report 1014848, PA, EMER SIREN, FIRE SIREN ISSUES FROM QCOS 9000-03, written in January 2010 identified degraded public address system speakers. Operations Department issued Standing Order 10-02 on January 11, 2010, to implement compensatory actions to ensure personnel are promptly notified of a hazardous plant condition in the affected areas.
Weaknesses in implementation of the standing order were identified by licensee staff and subsequently entered into the CAP on January 22, 2010, and again on February 10, 2010. Weaknesses included failure to notify Security or Emergency Response personnel who could have been responsible for accomplishing the actions of the standing order when the order was issued.
- As a follow up to the weaknesses identified in the standing order implementation discussed in the first bullet, NRC inspectors observed a training evaluation of operator performance in the simulator on February 12, 2010. As part of this observation, inspectors identified that the crew did not reference the standing order to otherwise indicate that compensatory measures were implemented when simulated area and site evacuations were announced over the public address system in the simulator. This performance deficiency was not identified by the training evaluators or discussed with the crew after the scenario until the NRC inspector raised the issue. This oversight was documented in the licensees CAP. Further discussion with Operations and Training personnel revealed that the standing order had not been incorporated into the training cycle for reinforcement and practice even though the order was expected to remain in place for up to a year while repairs were made to the public address system.
- On March 2, 2010, an inspector identified that tarps, put in place to protect Bus 23-1 and Bus 24-1 switchgear from ventilation heating coil leakage, obstructed Appendix R emergency lighting. Two emergency light fixtures, ELP 81A and 81B, were blocked from their designated targets by the tarps.
The station fire marshal then implemented the appropriate impairment documentation, entered the issue into the CAP, and contacted Operations to arrange for the tarps to be moved. The tarps were subsequently removed since the leak was no longer impacting the switchgear and the lights were verified to be properly aligned.
Each of these examples was evaluated under the appropriate guidance in Inspection Manual Chapter 0612 and determined to have minor risk significance. However, the combination of issues over a short period of time warrants additional evaluation for potential programmatic weaknesses in implementation of interim corrective action or compensatory measures. Following discussions, the licensee entered the observations into the CAP for resolution as IR 1054341, NRC Observation Regarding Implementation of Comp Measures.
.2 Daily Corrective Action Program Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.
These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.
b. Findings
No findings of significance were identified.
.3 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on concerns of possible preconditioning for infrequently scheduled maintenance activities occurring prior to and in conjunction with planned InService Test (IST) data collection for risk-significant valve stroke times. The inspectors considered the 4-year period of January 2006 through January 2010.
The review also included documents outside the normal CAP in work control documentation, system health reports, quality assurance audit/surveillance reports, and IST program documentation. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.
This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.
b. Findings
No findings of significance were identified.
.4 Annual Sample: Review of Operator Workarounds
a. Inspection Scope
The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of the operator workarounds on system availability and the potential for improper operation of the system, for potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents.
The inspectors performed a review of the cumulative effects of operator workarounds.
The documents listed in the Attachment to this report were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their CAP, and proposed or implemented appropriate and timely corrective actions which addressed each issue. Reviews were conducted to determine if any operator challenge could increase the possibility of an Initiating Event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of Mitigating Systems, impaired access to equipment, or required equipment uses for which the equipment was not designed. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds.
This review constituted one operator workaround annual inspection sample as defined in IP 71152-05.
b. Findings
No findings of significance were identified.
.5 Selected Issue Follow-Up Inspection: Clearance Order Released to Operations with
Switch Electrically Disconnected
a. Inspection Scope
During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting the failure of the 2-2001-171B valve in the radwaste system to open. The 2-2001-171B is the discharge header isolation valve for the 2B phase separator tank. The control switch was to be replaced per WO 306230. The technicians performing the job discovered that the new control switch was defective and backed out of the activity. The technicians properly documented in the work package that the old control switch was still installed with leads lifted. The supervisor did not review the work package prior to signing off the clearance order without clarifying notes to inform Operations that work would recommence at a later date and the control switch would be left out-of-service. Operations cleared the tags and attempted to use the control switch for AO 2-2001-171B, which failed to operate since the control switch was electrically disconnected.
Inspectors reviewed this issue per the licensee programs for clearance and tagging, configuration control, and for initiation of prompt investigations. Although a procedural performance deficiency did exist in compliance with documentation and notification of equipment status, inspectors determined the equipment status was properly documented in the work package and would have been restored in accordance with the work process. Inability to operate the valve was an operational inconvenience only with very little risk significance. The issue was entered into the CAP as Issue Report 1031403, 2-2001-171B Valve Not Opening. Thus, the issue had no safety consequences and was evaluated as minor in accordance with the examples in Inspection Manual Chapter 0609, Appendix E.
This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.
b. Findings
No findings of significance were identified.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report 05000254/2009-004-00: Pinhole Leak in Core Spray
Piping Results in Loss of Containment Integrity and Plant Shutdown for Repairs.
On September 8, 2009, during the performance of a quarterly 1A core spray (CS)system flow test, a pinhole leak was identified in the 1B CS minimum flow line just downstream of the 1B CS minimum flow valve. As a result, primary containment was declared inoperable and Quad Cities Unit 1 commenced a normal shutdown as required by Technical Specifications. Unit 1 was shut down during the morning of September 9, 2009.
The affected CS piping was removed and inspected. The inspection confirmed that an area of the pipe had severe wall thinning consistent with indications for cavitation erosion. The affected piping upstream and downstream of the 1B CS minimum flow valve was replaced. Ultrasonic testing was performed on all the other ECCS minimum flow lines on Unit 1. The testing verified that the wall thickness in all other Unit 1 ECCS minimum flow lines was acceptable. Unit 1 commenced a normal startup on September 10, 2009.
A review of the licensees flow accelerated corrosion (FAC) and cavitation corrosion programs was conducted. No regulatory compliance deficiencies were identified. The licensees programs are structured and administered in accordance with endorsed regulatory guidance and industry best practices. The 1B CS minimum flow piping was appropriately excluded from the scope of the FAC and cavitation corrosion programs as recommended by endorsed regulatory guidance and industry best practices. The licensee has added to the scope of their FAC and cavitation corrosion programs all ECCS minimum flow piping and other identified areas of piping in risk significant systems where the likelihood of a similar failure exist. These areas would include areas downstream of a flow orifice or where low temperature single phase fluid velocity is exceptionally high.
Corrective actions include the requirement to perform an ultrasonic testing following operation of the 1B core spray system for early detection of wall thinning until the slope of the piping can be modified during the next refueling outage. Documents reviewed as part of this inspection are listed in the Attachment to this report. This Licensee Event Report (LER) is closed.
This event follow-up review constituted one sample as defined in IP 71153-05.
4OA5 Other Activities
.1 (Open) NRC TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling,
Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01).
As documented in Sections 1R04 and 1R22, the inspectors confirmed the acceptability of the described licensees actions in response to potential gas accumulation issues as described in Generic Letter 2008-01. This inspection effort counts towards the completion of TI 2515/177, which will be closed in a later inspection report.
4OA6 Management Meetings
.1 Exit Meeting Summary
On April 6, 2010, the inspectors presented the inspection results to Mr. T. Tulon, and other members of the licensee staff. The licensee acknowledged the issues presented.
The inspectors confirmed that none of the potential report input discussed was considered proprietary.
.2 Interim Exit Meetings
Interim exits were conducted for:
- The results of the inservice inspection with Plant Manager, R. Gideon, on March 12, 2010.
The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- T. Tulon, Site Vice President
- W. Beck, Regulatory Assurance Manager
- D. Bowman, Operations Services Manager
- D. Collins, Radiation Protection Manager
- D. Craddick, Maintenance Director
- R. Dammann, Business Manager
- S. Darin, Engineering Director
- R. Gaylord, Training Support Manager
- J. Hansen, Licensing Manager
- V. Neels, Chemistry/Environ/Radwaste Manager
- D. Thompson, Security Manager
Nuclear Regulatory Commission
- M. Ring, Chief, Reactor Projects Branch 1
- S. Campbell, Branch Chief, NRR/Division of Reactor Licensing
- C. Gratton, NRR/Division of Reactor Licensing
- A. Howe, NRR/Division of Reactor Licensing
Illinois Emergency Management Agency
- C. Settles, Section Head
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened
2515/177 TI Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray System (NRC Generic Letter 2008-01)
Closed
- 05000254/2009-004-00 LER Pinhole Leak in Core Spray Piping Results in Loss of Containment Integrity and Plant Shutdown for Repairs Attachment