IR 05000254/2002005
| ML022110608 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 07/30/2002 |
| From: | Ring M Division Reactor Projects III |
| To: | Skolds J Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-02-005 | |
| Download: ML022110608 (46) | |
Text
July 30, 2002
SUBJECT:
QUAD CITIES NUCLEAR POWER STATION NRC INTEGRATED INSPECTION REPORT 50-254/02-05; 50-265/02-05
Dear Mr. Skolds:
On June 30, 2002, 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 June 26, 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 four issues of very low safety significance (Green). Three of these issues were determined to involve violations of NRC requirements. However, because of their very low safety significance and because they have been entered into your corrective action program, the NRC is treating these issues as Non-Cited Violations, in accordance with Section VI.A.1 of the NRCs Enforcement Policy. If you deny these Non-Cited Violations, you should provide a response with the basis for your denial, within 30 days of the date of this inspection report, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Quad Cities Nuclear Power Station.
The NRC has increased security requirements at the Quad Cities Nuclear Power Station in response to terrorist acts on September 11, 2001. Although the NRC is not aware of any specific threat against nuclear facilities, the NRC issued an Order and several threat advisories to commercial power reactors to strengthen licensees capabilities and readiness to respond to a potential attack. The NRC continues to monitor overall security controls and will issue temporary instructions in the near future to verify by inspection the licensees compliance with the Order and current security regulations. In accordance with 10 CFR 2.790 of the NRCs "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 NRCs 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 50-254/02-05, 50-265/02-05
REGION III==
Docket Nos:
50-254; 50-265 License Nos:
50-254/02-05, 50-265/02-05 Licensee:
Exelon Nuclear Facility:
Quad Cities Nuclear Power Station, Units 1 and 2 Location:
22710 206th Avenue North Cordova, IL 61242 Dates:
April 1 through June 30, 2002 Inspectors:
K. Stoedter, Senior Resident Inspector G. Wilson, Acting Senior Resident Inspector
J. Adams, Resident Inspector
M. Kurth, Resident Inspector D. Funk, Physical Security Inspector J. House, Senior Radiation Protection Inspector R. Lerch, Project Engineer P. Pelke, Reactor Engineer T. Ploski, Senior Emergency Preparedness Inspector Approved by:
Mark Ring, Chief Branch 1 Division of Reactor Projects
SUMMARY OF FINDINGS IR 05000254-02-05, IR 05000265-02-05, Exelon Nuclear, on 04/01 - 06/30/2002, Quad Cities Nuclear Power Station, Units 1 & 2, non-routine evolutions, operability evaluations, event follow-up, and other.
The inspection was conducted by resident and regional inspectors. This inspection identified four Green issues. Three of these issues involved Non-Cited Violations. 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/ASSESS/index.html.
A.
Inspector Identified Findings Cornerstone: Initiating Events Green. A lack of communications between operations personnel and an administrative senior reactor operators failure to participate in a formal shift turnover resulted in operations personnel commencing a Unit 2 reactor startup with the manual reactor head vent isolation valves in the open position. The failure to participate in a turnover was considered a Non-Cited Violation of Technical Specification 5.4.1.
The inspectors determined that this issue was of very low safety significance because the leak created by the open manual reactor head vent isolation valves was small, and adequate mitigating equipment was available to respond to a potential transient condition (Section 1R14).
Green. A digital feedwater control system design weakness, in conjunction with the inadvertent grounding of a pressure transmitter during an instrument maintenance surveillance, resulted in a manual reactor scram due to increasing reactor vessel water level.
The inspectors determined that this issue was of very low safety significance because the feedwater system would have been recoverable following a Level 8 isolation signal, and adequate mitigating systems equipment remained available to place and maintain the plant in a stable condition (Section 4OA3).
Cornerstone: Mitigating Systems Green. The inspectors identified a design deficiency and a Non-Cited Violation in that licensee personnel failed to perform a parts evaluation when installing hose clamps on the control rod drive system hydraulic accumulators instead of the seismically-qualified steel band clamps.
This issue was of very low safety significance because the design deficiency did not result in a loss of function as described in Generic Letter 91-18, Resolution of Degraded and Non-Conforming Conditions and on Operability (Section 1R15).
Green. The inspectors documented a Non-Cited Violation of 10 CFR 50.62, Anticipated Transient Without Scram Rule, due to the potential to lift the standby liquid control system relief valves during an anticipated transient without scram.
The inspectors determined that this finding was of very low safety significance because the standby liquid control system could be recovered during an anticipated transient without scram event, the cycling of the relief valves would allow a portion of the sodium pentaborate solution to be injected into the reactor vessel, and the plant remained within the acceptance criteria of the original anticipated transient without scram analyses during the relief valve lifts (Section 4OA5).
B.
Licensee Identified Findings Violations of very low safety significance which were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.
Report Details Summary of Plant Status:
Unit 1 began the inspection period at 100 percent power. On May 11 the operators reduced reactor power to 205 megawatts electric (MWe) to repair the actuator and gear box for condenser flow reversing valve 1-4402B, replace the main hydrogen seal oil pump, conduct control rod scram time testing, and perform turbine valve testing. The unit returned to full power the following day. One week later, operations personnel lowered reactor power to 525 MWe to perform a control rod pattern adjustment. Unit 1 operated at full power until May 20, when operators identified an increase in offgas system radiation levels. Due to the potential for leaking fuel, engineering placed restrictions on control rod movement. The restrictions resulted in reactor power decreasing to 99 percent by May 25 when engineering personnel worked with the operations staff to lower Unit 1 power to 55 percent to conduct flux suppression testing.
The suppression testing identified two separate core regions that likely contain failed fuel.
Unit 1 returned to full power on May 28. On June 1 operations personnel lowered reactor power by 10 percent to conduct control rod exercising near the failed fuel locations.
Unit 1 returned to full power on June 2. Operations personnel conducted turbine valve testing on June 14 which required reactor power to be reduced to 790 MWe for approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Unit 1 operated at full power for the remainder of the inspection period.
Unit 2 began the inspection period at criticality following a forced shutdown to repair an electro hydraulic control fluid leak and the 3E power operated relief valve. Nine hours after placing the turbine on line, operations personnel took the turbine off line due to a leak downstream of the turbine control valve on the B main steam line. At 7:16 p.m. on April 3, operations personnel placed the Unit 2 turbine on line and returned the unit to full power. Two days later, operations personnel inserted a manual scram due to a high reactor water level condition. On April 6 operations personnel placed the Unit 2 turbine on line. Unit 2 returned to full power on April 7, 2002. About 1 month later, operations personnel reduced power to approximately 550 MWe to replace the main hydrogen seal oil pump and returned to power later the same day. From May 24 - 26, reactor power was reduced to 550 MWe to conduct control rod scram time testing, replace the main hydrogen seal oil pump, and perform a rod pattern adjustment. Unit 2 returned to full power following these activities. On June 2 operations personnel lowered reactor power to approximately 450 MWe to perform a control rod pattern adjustment. Reactor power was returned to normal levels on June 4. On June 7, June 18, and June 20, unexpected changes in reactor power, reactor pressure, reactor vessel level, and main steam line flow occurred due to an issue with the reactor vessel internals. Unit 2 operated at near full power levels for the remainder of the inspection period.
1.
REACTOR SAFETY Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity 1R01 Adverse Weather Protection (71111.01)
a.
Inspection Scope The inspectors reviewed documents supporting the operation of the Service Water and Torus Cooling Systems including the status of open issues which might impact hot weather operation. The inspectors also reviewed plant wide actions taken to prepare for adverse weather, the status of planned actions, and the related procedures in place. The readiness of plant systems was discussed with the staff assigned to manage hot weather preparations.
b.
Findings No findings of significance were identified.
1R04 Equipment Alignment (71111.04)
a.
Inspection Scope The inspectors verified the system alignment of the following mitigating systems during the period:
Unit 1/2 emergency diesel generator;
Unit 1 reactor core isolation cooling system; and
Unit 1 high pressure coolant injection system The inspectors conducted 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 walked down the following risk significant areas to identify any fire protection degradations:
Fire Zone 1.1.1.3 Unit 1 Reactor Building Mezzanine;
Fire Zone 1.1.1.4 Unit 1 Reactor Building 3rd Floor;
Fire Zone 1.1.1.5 Unit 1 Reactor Building 4th Floor East;
Fire Zone 11.1.1.A 1D Residual Heat Removal Service Water and U1 Diesel Generator Cooling Water Pump Vault;
Fire Zone 11.1.1.C 1A Residual Heat Removal Service Water Pump Vault;
Fire Zone 11.1.2.A 2D Residual Heat Removal Service Water Pump Vault;
Fire Zone 11.1.2.B 2B and C Residual Heat Removal Service Water Pump Vault;
Fire Zone 11.1.2.C 2A Residual Heat Removal Service Water Pump, U2 Diesel Generator Cooling Water Pump Vault;
Fire Zone 11.2.1 1B Core Spray Room;
Fire Zone 11.2.2 1B Residual Heat Removal Room;
Fire Zone 11.2.3 1A Core Spray Room; and
Fire Zone 11.2.4 1A Residual Heat Removal Room The inspectors placed an emphasis on control of transient combustibles and ignition sources; the material condition, operational lineup, and operational effectiveness of the fire protection systems, equipment, and features; and the material condition and operational status of fire barriers used to prevent fire damage or fire propagation.
The inspectors verified that transient combustibles were controlled in accordance with the licensees procedures. During a walkdown of each fire zone, the inspectors observed the physical condition of fire suppression devices and passive fire protection equipment such as fire doors, barriers, and penetration seals. The inspectors observed the condition and placement of fire extinguishers and hoses against the Pre-Fire Plan fire zone maps. The physical condition of passive fire protection features such as fire doors, fire dampers, fire barriers, fire zone penetration seals, and fire retardant structural steel coatings were also inspected to verify proper installation and physical condition.
b.
Findings No findings of significance were identified.
1R06 Flood Protection Measures (71111.06)
a.
Inspection Scope The inspectors reviewed Quad Cities Abnormal Procedure (QCOA) 0010-16, "Flood Emergency Procedure," to determine internal and external design flood levels for the site and areas of the plant containing equipment important to safety. The inspectors performed a detailed walkdown of flood protection features for the residual heat removal
service water pump vaults and the Unit 1 and Unit 2 core spray pump rooms. The pump rooms contained safety-related mitigating systems susceptible to flooding from both internal and external sources. During the walkdown the inspectors verified equipment below the flood line was sealed; no holes or unsealed penetrations in floors and walls existed between flood areas; watertight doors between flood areas were maintained and in good material condition; and common drain systems and sumps, including floor drain piping and check valves were operable where credited for flood area isolation.
The inspectors verified that the licensee was able to perform the actions specified in QCOA 0010-16, "Flood Emergency Procedure." The inspectors confirmed availability of a pump and equipment designated to provide makeup water to the fuel pool in the event of an external flood in excess of 594 feet above mean sea level.
The inspectors reviewed the corrective actions program database for past flooding events and documentation of previous NRC findings associated with flood protection.
The inspectors verified that the licensee entered problems into their corrective action program and the problems were properly addressed for resolution.
b.
Findings No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
a.
Inspection Scope On April 15, 2002, the inspectors observed licensed operator requalification training conducted in accordance with Operating Exam Number Three Guide, Main Steam Line Flow Instrument Failure/Large Loss Of Coolant Accident/Reactor Pressure Vessel Flooding.
The inspectors verified crew performance in terms of clarity and formality of communication; the ability to take timely action; the prioritizing, interpreting, and verifying of alarms; the correct use and implementation of procedures; timely control board operation and manipulation; and the shift managers ability to identify and implement Technical Specification and emergency plan actions.
b.
Findings No findings of significance were identified.
1R12 Maintenance Rule Implementation (71111.12)
a.
Inspection Scope The inspectors reviewed the licensees implementation of maintenance rule requirements, including a review of scooping, goal-setting, performance monitoring, short-term and long-term corrective actions, and current equipment performance for the following systems:
Reactor Protection System; and
Division II Alternating Current The inspectors independently verified that the systems were appropriately classified as (a)(1) or (a)(2); that performance criteria for systems classified as (a)(2) were appropriate; and that the corrective actions for systems classified as (a)(1) were adequate.
b.
Findings No findings of significance were identified.
1R13 Maintenance Risk Assessment and Emergent Work Evaluation (71111.13)
a.
Inspection Scope The inspectors reviewed the licensees evaluation of risk, activity scheduling, configuration control, and emergent work to ensure that plant risk was appropriately managed. The inspectors verified that licensee actions, such as establishing compensatory actions, minimizing the duration of the activity, obtaining appropriate management approval, and informing appropriate plant staff to address increased online risk during these periods were accomplished when needed. The following work week activities were reviewed:
Work Week Reviewed Systems Out of Service During Work Week Week of April 6, 2002 Unit 1 emergency diesel generator, 1B residual heat removal valve, reactor core isolation cooling, high pressure coolant injection, and emergent work on the electro-hydraulic control system Week of April 13, 2002 1B control room emergency ventilation, 2B residual heat removal, 2C and 2D residual heat removal service water pumps, and reactor core isolation cooling Week of April 20, 2002 Unit 1 high pressure coolant injection, dredging in the intake bay, and switchyard breaker 4-6 Week of May 4, 2002 Unit 1 reactor core isolation cooling, 1/2 B standby gas treatment, 1A core spray, and dredging in the intake bay.
Week of May 13, 2002 1B residual heat removal pump, a station blackout diesel generator, Unit 1 main hydrogen seal oil pump, 1/2 emergency diesel generator, and 2A residual heat removal
Week of May 20, 2002 Unit 2 high pressure coolant injection, Unit 2 high pressure coolant injection room cooler, 2A stator water heat exchanger, 2A control rod drive pump, and testing of the Unit 2 group 3 containment isolation valves b.
Findings No findings of significance were identified.
1R14 Non-Routine Evolutions (71111.14)
.1 Manual Reactor Head Vent Isolation Valves Found Open During Unit 2 Startup Activities a.
Inspection Scope The inspectors reviewed Condition Report 97694, Unit 2 Reactor Head Vent Bypass Valves Found Open, the apparent cause evaluation, and associated procedures, and interviewed operations personnel to determine the circumstances which led to starting up and pressurizing the Unit 2 reactor to 50 pounds with the reactor head vent isolation valves open.
b.
Findings The inspectors identified one green finding involving a non-cited violation for a lack of communications between operations personnel and an administrative senior reactor operators failure to participate in a formal shift turnover which resulted in operations personnel commencing a Unit 2 reactor startup with the manual reactor head vent isolation valves in the open position Background On March 4, 2002, operations personnel received alarm 902-4, Unit 2 Drywell Equipment Drain Sump High Temperature. Operations and radiation protection personnel responded to the drywell to measure the temperature of pipes that interface with the drywell equipment drain sump. The operators in the drywell identified that the common drain line downstream of the reactor head vents had reached 210 degrees Fahrenheit. One operator and one radiation protection technician proceeded to the drywell basement to inspect the drywell equipment drain sump. This inspection was unable to be completed due to the amount of steam in the drywell basement. The remaining operator and radiation technician continued to perform general leak inspections and identified that the manual reactor head vent isolation valves had been left open. The operator closed the head vent isolation valves and the steam in the drywell basement diminished. No other sources of leakage were identified.
The licensee determined that the manual reactor head vent isolation valves had been left open due to inadequate communications between operations personnel and the failure to perform an adequate turnover. During the outage, multiple work activities and surveillance tests were conducted which required the head vent isolation valves to be
open. Although the restoration steps for many of the work activities or surveillance tests directed that the head vent isolation valves be closed, operations personnel took appropriate steps to leave the valves open to allow continued surveillance testing. In addition to documenting the status of the valves within specific surveillance procedures, operations personnel placed an equipment status tag on the control room panels to alert operations personnel to the abnormal condition of the head vent isolation valves.
On March 3, 2002, a unit nuclear station operator (licensed reactor operator) noticed the head vent isolation valve equipment status tag on the control room panels. The nuclear station operator removed the equipment status tag and handed it to the administrative senior reactor operator (Admin SRO). After the head vent isolation valves were discovered open, the Admin SRO stated that he believed the nuclear station operator had said that the equipment status tag had been resolved. No action was taken to confirm the information communicated by the nuclear station operator or to verify the position of the head vent isolation valves. In addition, the Admin SRO had not participated in a formal turnover prior to assuming his duties as part of the operating shift. As a result, the Admin SRO was not aware of previous discussions regarding equipment status tag resolution. This contributed to removing the equipment status tag even though no action had been taken to close the head vent isolation valves.
Significance Evaluation The inspectors determined that the safety significance of the manual reactor head vent isolation valves being left open during reactor startup was more than minor because if left uncorrected, the issue may become more of a safety concern due to leakage from the common drain line possibly being masked by the feedwater system and because the issue impacted the integrity of the reactor coolant system. The inspectors continued to screen this issue using the Phase 1 screening worksheet. This worksheet was used rather than screening the issue using the Shutdown Significance Determination Process because operations personnel had secured the residual heat removal system from shutdown cooling. The inspectors determined that the Phase 1 screening worksheet was not an adequate tool to screen this issue since the At Power Significance Determination Process assumed that the reactor was operating at normal temperatures and pressures. The inspectors discussed the risk tool inadequacies with the senior reactor analyst who agreed to perform a bounding Phase 2 analysis.
The senior reactor analyst determined that the Significance Determination Process Worksheet for transients should be evaluated and determined that the safety significance of the manual reactor head vent isolation valves being left open during reactor startup was very low (Green) because the leak created by the valves being left open was not of a sufficient size to impact the availability of the power conversion system function or other available mitigating systems equipment.
Enforcement Technical Specification 5.4.1 requires that written procedures be established, implemented, and maintained covering the applicable procedures recommended in
Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, Section 1g requires procedures for shift relief and turnover. Procedure OP-AA-112-101, Shift Turnover and Relief, is the licensees procedure addressing the requirements of Regulatory Guide 1.33, Section 1g. Step 3.1 of Procedure OP-AA-112-101 states that all shift personnel are responsible for reviewing and understanding the logs and checklists applicable to their shift position before assuming the shift. The inspectors determined that the failure of the Admin SRO to participate in a shift turnover that included a review of logs and checklists applicable to the Admin SRO position prior to assuming the shift was a violation of Technical Specification 5.4.1. However, this violation is not being cited in accordance with Section VI.A.1 of the NRCs Enforcement Policy (NCV 50-265/02-05-01). This issue was included in the licensees corrective action program as Condition Report 112360.
.3 Unexpected Change in Unit 2 Operating Parameters a.
Inspection Scope On June 7 operations personnel identified that main steam line A flow had increased from 2.95 to 3.05 million pounds per hour and that flow in the three remaining steam lines decreased. Approximately 2-3 minutes later, operations personnel observed reductions in reactor pressure, reactor vessel level, reactor power, and feedwater flow.
The inspectors reviewed operator logs, available plant data, and procedures to determine the appropriateness of operator actions in response to this transient. The inspectors performed similar reviews for additional transients which occurred on June 18 and June 20. The inspectors observed multiple meetings between the licensee and General Electric which were held to determine the cause of the transient and corrective actions. Personnel from the Office of Nuclear Reactor Regulation, Region III, and the resident inspector office also participated in a conference call with the licensee regarding the information provided by General Electric, the licensees operability evaluation, and potential impacts on continued operation of Unit 2.
b.
Findings No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
.1 Missing or Inadequate Seismic Restraining Clamps on Multiple Control Rod Drive Accumulators a.
Inspection Scope The inspectors reviewed the operability evaluation performed for Condition Report 98263, Unauthorized Retaining Clamps Used for Hydraulic Control Unit Accumulators, to determine the impact that the unauthorized clamps had on system operability.
b.
Findings
One Green finding involving a Non-Cited Violation of 10 CFR 50, Appendix B, Criterion III, Design Control, was identified due to the failure to properly evaluate the replacement of the required seismic steel band clamps with hose clamps.
Background At Quad Cities each control rod drive hydraulic accumulator should have two steel bands installed to ensure that this portion of the control rod drive system remains intact during and following a seismic event. On February 28, 2002, Quad Cities personnel received a nuclear operations notification (part of the stations operating experience process) describing that one or both of the steel bands were missing on multiple accumulators at Oyster Creek Station. The operating experience coordinator reviewed the notification in accordance with Procedure RS-AA-115, Operating Experience, and concluded that the potential missing steel clamps did not impact the operability of the control rod drive system. As a result, the operating experience coordinator assigned an action item to reactor engineering to review the notification within 30 days.
On March 7, 2002, the inspectors at Dresden Station contacted the inspectors at Quad Cities Station and informed them that engineers had identified missing clamps on several accumulators at Dresden Station. The Quad Cities Station resident inspectors contacted the shift manager to determine if he was aware that the control rod drive accumulators on both units may be degraded. The inspectors were also concerned that if missing clamps were identified on Unit 2, operations personnel may have changed operating modes with inoperable accumulators which is prohibited by Technical Specifications.
Following discussions with the inspectors, the shift manager learned that engineering personnel had conducted a walk down of each units control rod drive accumulators.
Engineering personnel identified two control rod drive accumulators on Unit 1 (34-43 and 46-27) and two on Unit 2 (22-59 and 38-03) that either had hose clamps installed instead of the required steel seismic bands or were missing clamps. The inadequate or missing clamps were immediately replaced with the appropriate steel band clamps.
Engineering personnel also completed an operability evaluation to determine whether the accumulators were operable prior to the clamps being replaced.
The inspectors reviewed the operability evaluation and agreed with the licensees conclusion that the accumulators remained operable. However, the inspectors questioned the licensee to determine if a parts evaluation addressing the change in design had been completed prior to the installation of the hose clamps. The licensee was unable to find any documentation that justified the design change. The licensee wrote Condition Report 104321 to document the missing design change evaluation.
Significance Evaluation The inspectors determined that the failure to ensure an adequate design review was performed prior to changing the design of a safety related component was more than minor since if left uncorrected, it could become a more significant safety concern and because the issue could affect the reliability of a mitigating system. The inspectors
used the Significance Determination Process Phase 1 Screening Worksheet and determined that this issue was of very low safety significance (Green) because the design deficiency did not result in a loss of function as described in Generic Letter 91-18, Resolution of Degraded and Non-Conforming Conditions and on Operability.
Enforcement Actions 10 CFR 50, Appendix B, Criterion III, Design Control, requires that measures shall be established for the selection and review for suitability of application of materials, parts, and equipment that are essential to the safety-related functions of structures, systems, and components. The failure to ensure that the selection and suitability of hose clamps for the control rod drive hydraulic accumulators was appropriate instead of the steel band clamps was considered a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III (NCV 50-254/02-05-03; 50-265/02-05-03) in accordance with Section VI.A.1 of the NRCs Enforcement Policy. The issue was entered into the licensees corrective action program as Condition Report 104321.
.2 Review of Other Operability Determinations a.
Inspection Scope
The inspectors reviewed the operability evaluations associated with a degraded 1A residual heat removal system heat exchanger, the lack of gland seal water to the Unit 1 diesel generator cooling water pump, degraded auxiliary contacts on multiple motor control centers, and unexpected power changes due to possible dryer degradation. 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.
1R19 Post-Maintenance Testing (71111.19)
a.
Inspection Scope The inspectors reviewed and observed the following post-maintenance testing activities involving risk significant equipment in the Mitigating Systems and Barrier Integrity Cornerstones:
Work Order 423819 Unit 2 3E Power Operated Relief Valve;
Work Order 379753 Unit 1/2 Emergency Diesel Generator;
Work Order 408294 Unit 1 High Pressure Coolant Injection; and
Work Order 452432 Unit 1 B Residual Heat Removal Service Water System The inspectors verified that the post maintenance tests were adequate for the scope of the maintenance work performed, that the test acceptance criteria were clear, and that the tests demonstrated operational readiness consistent with design and licensing basis documents. The inspectors also verified that the impact of the testing had been properly characterized during the pre-job briefing; the tests were performed as written; all testing prerequisites were satisfied; and that the test data was complete. Following the completion of the tests, the inspectors verified that test equipment was removed and that the systems were returned to their normal standby 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 and Barrier Integrity Cornerstones:
QCIS 0700-22, Unit 1 Division II Power Operation APRM Functional Test;
QCOS 1400-08, Core Spray System Power Operated Valve Test;
QCOS 6600-41, Unit 1 Diesel Generator Load Test;
QCOS 6600-42, Unit 2 Diesel Generator Load Test;
QCOS 6600-03, Diesel Fuel Oil Transfer Pump Monthly Operability;
QCOS 6600-02, Diesel Generator Air Compressor Operability;
QCOS 0203-07, Unit 2 Auto Blowdown Initiation Logic Test;
CY-QC-120-600, Off-Gas Sampling;
CY-QC-130-401, Off-Gas Isotopic Analyses Recombiner Outlet and Adsorber Inlet Samples;
QCOS 1600-45, Unit 2 Primary Containment Isolation Group 3 Test; and
QCOS-1000-06, Residual Heat Removal/LOOP Operability Test
The inspectors verified that the structures, systems, and components selected were capable of performing their intended safety function and that the surveillance tests satisfied the requirements contained in Technical Specifications, the Updated Final Safety Analysis Report, and licensee procedures. During surveillance testing observations, the inspectors verified that the test demonstrated operational readiness consistent with design and licensing basis documents and that the test acceptance criteria were clear. The inspectors also verified that the impact of the testing had been properly characterized during the pre-job briefing; the test was performed as written; the test data was complete and met the requirements of the testing procedure; and the test equipment range and accuracy was consistent with the application. Following test completion, the inspectors verified that the test equipment was removed and that the system was returned to its normal standby configuration.
b.
Findings No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a.
Inspection Scope The inspectors reviewed Design Change Package 330658 used to modify and repair feedwater manual isolation valve 2-0220-057A and the associated 10 CFR 50.59 screening. The inspectors compared the contents of the design change package and the 50.59 screening to design basis information contained in the Updated Final Safety Analysis Report, Technical Specifications, and the Technical Requirements Manual.
The inspectors also reviewed the design change package to ensure the applicable American Society of Mechanical Engineers code requirements were met during the repair.
b.
Findings No findings of significance were identified.
Cornerstone: Emergency Preparedness 1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
a.
Inspection Scope The inspectors reviewed Revision 14 of the Quad Cities Nuclear Power Station Annex to the Exelon Nuclear Standardized Radiological Emergency Plan to determine whether changes identified in Revision 14 reduced the effectiveness of the licensees emergency planning, pending onsite inspection of the implementation of these changes.
b.
Findings No findings of significance were identified.
1EP6 Drill Evaluation (71114.06)
.1 Review of April 19, 2002, Emergency Preparedness Drill Activities a.
Inspection Scope The inspectors observed the drill scenario and the licensees emergency preparedness activities from the simulator and the technical support center. Specific activities observed or assessed included the accuracy and timeliness of emergency classifications, notifications, and protective action recommendations and the thoroughness of the licensees critique. The inspectors also reviewed the licensees determination of successful and failed opportunities under the Drill and Exercise Performance Indicator to ensure the determinations were made in accordance with Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline.
b.
Findings No findings of significance were identified.
.2 Review of June 12, 2002 Emergency Preparedness Pre-Exercise a.
Inspection Scope The inspectors observed the licensees emergency preparedness pre-exercise from the simulator and technical support center. The scenario began with an earthquake which caused operations personnel in the simulator to declare an unusual event. Once personnel confirmed that the acceleration caused by the earthquake was greater than
.1g, the shift manager upgraded the event to the alert status. A site emergency was declared when two of the three fission product barriers were lost. Emergency operations facility personnel upgraded the event classification to a general emergency following the identification that the third fission product barrier may be lost. The inspectors assessed the accuracy and timeliness of emergency classifications, notifications, and protective action recommendations to ensure that successful and failed opportunities were appropriately captured for inclusion in the specific NRC performance indicator. The inspectors also observed the licensees critique to ensure that items identified by the inspectors were also identified by the licensee.
b.
Findings No findings of significance were identified.
2.
RADIATION SAFETY Cornerstone: Occupational Radiation Safety 2OS1 Access Controls To Radiologically Significant Areas (71121.01)
.1 Control of Non-Fuel Materials Stored in the Spent Fuel Pool a.
Inspection Scope The inspector evaluated the licensees procedure and practices for the control of highly activated or contaminated materials (non-fuel) stored within the spent fuel pool or other storage pools in order to verify that controls for underwater storage of non-fuel materials were adequate, the materials were accounted for and that the administrative and physical controls for the underwater storage of non-fuel materials were consistent with the licensees procedure, Regulatory Guide 8.38, Control of Access to High and Very High Radiation Areas in Nuclear Plants and Information Notice 90-33, Sources of Unexpected Occupational Radiation Exposures at Spent Fuel Storage Pools. The Spent Fuel Storage Pool Inventory Control and Audit Procedure along with the Spent Fuel Storage Pool Inventory Log were reviewed; radiation protection and reactor services staff were interviewed; and a walkdown of the refuel floor was conducted.
b.
Findings No findings of significance were identified.
.2 Identification and Resolution of Problems a.
Inspection Scope The inspector evaluated the effectiveness of the stations problem identification and resolution processes to identify, characterize and prioritize problems, and to develop and implement corrective actions. The evaluation included: (1) the results of a focus area self-assessment of the as-low-as-reasonably-achievable (ALARA) Planning and Control Program performed during 2002; (2) a Nuclear Oversight continuous assessment report along with field observation reports of the Radiation Protection Program (Access Control and ALARA programs) that were completed in calendar years 2001 and 2002; and (3) the licensees condition report (CR) database and individual CRs related to the Access Control and ALARA programs for years 2001-2002.
The licensees corrective action program for Radiation Protection was evaluated to verify that problems were appropriately prioritized and resolved in a timely manner, and commensurate with their importance based on safety and risk. This evaluation included procedure and documentation reviews, discussions of the program with cognizant licensee personnel, and observing management meetings in which condition reports were evaluated.
b.
Findings No findings of significance were identified.
20S2 ALARA Planning and Controls (71121.02)
.1 Source Term Reduction and Control a.
Inspection Scope The inspector reviewed the status of the stations source term reduction program focusing on those initiatives having a major impact on outage dose. This included cobalt/stellite reduction, chemistry management, chemical decontamination, permanent shielding, hydrolasing/flushing evolutions, shutdown practices to minimize source term transportation, and system enhancements. The inspector also assessed the general trend of the stations total source term to evaluate the effectiveness of the stations source term reduction plan.
b.
Findings No findings of significance were identified.
.2 Declared Pregnant Workers a.
Inspection Scope The inspector reviewed the stations dose minimization controls used for declared pregnant workers. Specifically, the inspector reviewed the licensees adherence to the requirements contained in 10 CFR 20.1208 by examining the licensees fetal protection program procedure for tracking radiological exposure to the embryo/fetus, and the administrative and ALARA controls that could be used by the licensee to minimize the dose to the embryo/fetus of a declared pregnant worker.
b.
Findings No findings of significance were identified.
Cornerstone: Public Radiation Safety 2PS2 Radioactive Material Processing and Transportation (71122.02)
.1 Shipment Records a.
Inspection Scope The inspector reviewed one radioactive material and radwaste shipment manifest and associated records for a non-excepted shipment (Low Specific Activity II) from April 2002. The review was performed to verify compliance with NRC requirements
contained in 10 CFR Parts 20, 61, and 71, and the Department of Transportation (DOT)
requirements of 49 CFR Parts 172 and 173. The records were reviewed to verify that package and transport vehicle surveys satisfied DOT requirements, and that shipment manifests were completed in accordance with the regulations and included appropriate emergency response information.
b.
Findings No findings of significance were identified.
3.
SAFEGUARDS Cornerstone: Physical Protection 3PP1 Access Authorization (AA) Program (Behavior Observation Only) (71130.01)
a.
Inspection Scope The regional security inspector interviewed five supervisors and five non-supervisors (both licensee and contractor employees) to determine their knowledge level and practice of implementing the licensees behavior observation program responsibilities.
Selected procedures pertaining to the Behavior Observation Program and associated training activities were also reviewed. Also licensee fitness-for-duty semi-annual test results were reviewed. In addition, the inspector reviewed a sample of licensee self-assessments, audits, and security logged events. The inspector also interviewed security managers to evaluate their knowledge and use of the licensees corrective action system.
b.
Findings No findings of significance were identified.
3PP2 Access Control (Identification, Authorization and Search of Personnel, Packages, and Vehicles) (71130.02)
a.
Inspection Scope
The regional security inspector reviewed the licensees protected area access control testing and maintenance procedures. The inspector observed licensee testing of all access control equipment to determine if testing and maintenance practices were performance based. On two occasions, during peak ingress periods, the inspector observed in-processing search of personnel, packages, and vehicles to determine if search practices were conducted in accordance with regulatory requirements.
Interviews were conducted and records were reviewed to verify that security staffing levels were consistently and appropriately implemented. Also the inspector reviewed the licensees process for limiting access to only authorized personnel to the protected area and vital equipment by a sample review of access authorization lists and actual
vital area entries. The inspector reviewed the licensees program to control hard-keys and computer input of security-related personnel data.
The regional security inspector reviewed a sample of licensee self-assessments, audits, maintenance request records, and security logged events for identification and resolution of problems. In addition, the inspector interviewed security managers to evaluate their knowledge and use of the licensees corrective action system.
b.
Findings No findings of significance were identified.
4.
OTHER ACTIVITIES 4OA1 Performance Indicator Verification (71151)
.1 Review of Initiating Events Cornerstone Performance Indicators a.
Inspection Scope The inspectors reviewed the licensees performance indicator data sheets, operator logs, monthly operating reports, licensee event reports, previous inspection reports and condition reports and conducted independent calculations to verify, for each unit, the Reactor Scrams and Reactor Scrams with Loss of Heat Removal performance indicators for the period of July 2001 through March 2002, and the Unplanned Power Changes per 7000 Critical Hours performance indicator for the period of July 2001 through May 2002.
b.
Findings No findings of significance were identified.
.2 Review of Physical Security Cornerstone Performance Indicators a.
Inspection Scope The regional security inspector verified the data for the Physical Protection Performance Indicators pertaining to Fitness-For-Duty Personnel Reliability, Personnel Screening Program, and Protected Area Security Equipment. Specifically, a sample of plant reports related to security events, security shift activity logs, fitness-for-duty reports, and other applicable security records were reviewed for the period between November 2000 and December 2001.
b.
Findings No findings of significance were identified.
4OA2 Identification and Resolution of Problems (71152)
a.
Inspection Scope The inspectors reviewed a sample of condition reports, cause determinations, and corrective actions listed in the list of documents reviewed section of this report to determine if the licensee was identifying human performance issues and taking corrective actions commensurate with the significance of the issues. The inspectors also evaluated the licensees extent of condition review, potential generic implications, and common cause determination.
b.
Findings The inspectors determined that a large number of human performance related problems had occurred in 2002. Although the human performance problems were identified through self-revealing plant issues or events, the licensee initiated condition reports to evaluate the root, apparent, and/or contributing causes for most issues and developed actions to correct each condition.
In January 2002 the licensee initiated Condition Report 92430 to document an increase in human performance problems. The prompt corrective actions consisted of instituting a temporary program to make all employees more aware of the importance of fundamentals when performing work activities. The inspectors determined that human performance related problems continued to occur in February 2002 indicating that the temporary program may not have been effective in reducing the number of human performance related issues at the station.
In March 2002 the licensee conducted a common cause review for Condition Report 92430 and determined that a large portion of the human performance problems were related to substandard verification practices such as self-check and peer-check.
Complacency with standards for items such as pre-job briefs was also determined to be a contributor. The corrective actions developed as part of the common cause review included developing and implementing a plan to increase the use of fundamentals known to prevent human performance issues. The licensee also instituted human performance review boards to identify human performance issues that had resulted in plant issues or events.
On March 14 the licensee expanded the common cause analysis performed for Condition Report 92430 to include February 2002 data and determine any relationships between the human performance problems. The expanded common cause report was completed on May 15, 2002. The human performance coordinator determined that the causes for the February 2002 human performance issues were different than those identified during the review of January 2002 events. Specific causes included weaknesses in work planning, questioning attitude, procedure adherence, self-check, and peer-check. In response to the new issues, the licensee implemented a paired observation program to provide employees with real-time feedback associated with their work activities. A short time later, senior licensee management determined that individuals performing as assessors in the paired observation program were not as critical as expected. This was of concern since a lack of criticalness may impact the
effectiveness of the licensees corrective actions and result in no significant changes in human performance. At the conclusion of the inspection period, the licensee had taken actions to improve the feedback provided as part of the paired observation program.
The effectiveness of these actions was unable to be determined.
The inspectors conducted an independent review of condition reports and agreed with the licensees assessment regarding the causes for the recent human performance problems. The inspectors determined that the licensee was documenting human performance related issues as part of the corrective action program and taking actions to correct the conditions. Due to the fact that human performance related problems continue to occur, and the short amount of time the licensees corrective actions have been in effect, the inspectors were unable to determine the effectiveness of the licensees proposed corrective actions.
4OA3 Event Followup (71153)
.1 Reactor Scram Caused by Design Weakness in Digital Feedwater Control System and Unintended Ground of Plant Equipment a.
Inspection Scope On April 5, 2002, operations personnel manually scrammed the Unit 2 reactor due to high reactor vessel water level. The inspectors observed operator and plant performance from the control room to ensure that the response to the transient was in accordance with procedures. The inspectors reviewed plant parameters, the operation of mitigating systems, the integrity of fission product barriers and confirmed that the licensee properly reported the event as required by 10 CFR 50.72.
b.
Findings One Green finding was identified due to the failure to properly design the digital feedwater level control system to withstand an inadvertent grounding of plant instrumentation.
Background At 10:00 a.m. on April 5, 2002, operations personnel granted permission for two instrument maintenance technicians to perform instrument surveillance QCIS 0600-02, Unit 2 Reactor Pressure 0 to 1200 psig Indication Calibration, on pressure transmitter 2-0647A. Personnel at the digital feedwater level control system operator station placed transmitter 2-0647-A in the calibrate mode. The use of the calibrate mode allowed the output of the pressure transmitter to be disconnected from the control system logic.
With the pressure transmitters output disconnected from the control system logic, licensee personnel believed that the calibration of the transmitter could continue without impacting the digital feedwater control system.
Approximately 4 minutes later, operations personnel detected a hard failure signal error on the 2A reactor feed pump suction pressure transmitter. Total indicated feedwater flow dropped from 10.81 million pounds per hour (mlb/hr) to 9.73 mlb/hr. The
digital feedwater level control system continued to show a reduction in total indicated feedwater flow to 4.85 mlb/hr. The apparent mismatch between steam flow and feedwater flow caused the 2A and 2B feedwater regulating valves to go to 80 percent open. Opening of the feedwater regulating valves caused the total indicated feedwater flow to increase to 6.64 mlb/hr. Although the digital feedwater control system initially displayed that total indicated feedwater flow had dropped from 10.81 mlb/hr to 9.73 mlb/hr, total feedwater flow had actually increased from 10.81 mlb/hr to 13.5 mlb/hr.
The large increase in actual feedwater flow resulted in operations personnel manually scramming the reactor after reaching the pre-established manual scram criteria.
Root Cause In February 2002 Quad Cities Station installed a digital feedwater level control system on Unit 2. The licensee believed the digital control system was designed such that the system would switch from three-element to single-element control when the current signal in an instrument loop dropped to less than 2 milliamps. The licensee identified that the vendor supplied fuse holders installed as part of the digital feedwater level control system contained light emitting diodes (for fuse failure identification) wired in parallel with the fuses. On April 5, 2002, the instrument maintenance technicians made a human performance error when they grounded pressure transmitter 2-0647-A during calibration. The grounding caused the fuse for the instrument loop containing pressure transmitter 2-0647-A, the 2A reactor feed pump suction pressure transmitter, and the 2A reactor feed pump feedwater flow transmitter to blow. The blown fuse should have resulted in a reduction of the instrument loop current to less than 2 milliamps. However, the licensee discovered that following a fuse failure, a sneak current continued to supply the light emitting diodes on the fuse holder such that instrument loop current remained greater than 2 milliamps and prevented the digital feedwater level control system from converting to single-element control.
Significance Evaluation The inspectors determined that this issue was more than minor since it had an actual impact on safety, resulted in an increase in the transient initiating event frequency, and effected the function of a mitigating system. The inspectors evaluated this issue using the Phase 1 Significance Determination Process Screening Worksheet and determined that the failure to adequately design the digital feedwater level control system to withstand an inadvertent grounding of an instrument under calibration required a Phase 2 analysis because the issue contributed to the likelihood of a reactor scram and the likelihood that mitigating equipment or functions may not be available. The inspectors performed the Phase 2 risk analysis and determined that this issue was of very low safety significance (Green) because the feedwater system could be recovered even if reactor vessel water level exceeded Level 8 and adequate mitigating systems equipment remained available to place and maintain the plant in a stable condition (FIN 50-265/02-05-04).
Enforcement The inspectors determined that no violations of NRC requirements occurred during the design of the digital feedwater system or during the calibration of pressure transmitter 2-0647-A on April 5, 2002, due to the digital feedwater level control system being non safety-related.
.2 Review of Licensee Event Reports a.
Inspection Scope The inspectors performed an onsite review of records to evaluate the root cause and corrective actions for the licensee event reports discussed in the Findings section below. The inspectors evaluated the timeliness, completeness, and adequacy of the root cause and corrective actions in accordance with the requirements of 10 CFR Part 50, Appendix B, as appropriate.
b.
Findings (Closed) Licensee Event Report 50-254/00-001-01: Automatic Reactor Scram from Low Reactor Vessel Level. The inspectors reviewed the licensees initial event report as part of the inspection activities documented in Sections 1R14 and 4OA3 of Inspection Report 50-254/00-00; 50-265/00-20. On April 29, 2002, the licensee submitted a revision to the event report to document pertinent root cause and corrective action information. The inspectors reviewed the revised event report and found that the new information did not change the inspectors initial assessment of licensee performance during the reactor scram.
(Closed) Licensee Event Report 50-254/00-002-01: Inadequate Calibration of Post Accident Torus Temperature Monitors. The inspectors documented one green finding involving a Non-Cited Violation during a review of the initial event report (see Inspection Report 50-254/00-15; 50-265/00-15). On April 29, 2002, the licensee submitted a revised event report to incorporate pertinent root cause and corrective action information. The inspectors reviewed the revised event report and determined that the new information did not change the inspectors initial assessment of the event.
(Closed) Licensee Event Report 50-265/02-001-00: High Pressure Coolant Injection System Uncoupled Above 150 psig due to Misapplication of Technical Specifications.
On March 4, 2002, operations personnel increased reactor pressure above 150 psig with the HPCI turbine disconnected from the pump. The decision to raise reactor pressure above 150 psig was contrary to Technical Specification 3.0.4. The inspectors documented the circumstances surrounding this event, and the risk associated with exceeding 150 psig reactor pressure with the HPCI turbine disconnected, in Section 4OA7 of this report.
(Closed) Licensee Event Report 50-265/02-002-00: Manual Scram due to Reactor Vessel Level Transient as a Result of a Digital Feedwater Level Control System Design Error. On April 5, 2002, operations personnel inserted a manual reactor scram due to increasing reactor vessel water level. The licensee determined that the increasing level
was caused by a digital feedwater control system design error in conjunction with inadvertent grounding of a pressure transmitter during an instrument maintenance surveillance. The inspectors documented the circumstances surrounding this event, and the risk associated with this initiating event, in Section 4OA3 of this report.
4OA5 Other
.1 (Closed) Unresolved Item 50-254/01-05-02; 50-265/01-05-02: This unresolved item involved the licensees methods for changing maintenance rule performance criteria, the failure to update the Probabilistic Risk Assessment Report every two years as required by procedure, and the decision not to establish condition monitoring criteria for maintenance rule components when maintenance rule performance criteria were too small to be effectively monitored. The Office of Nuclear Reactor Regulation (NRR)
determined that the licensees use of Electric Power Research Institutes (EPRI)
TR-105369, Probabilistic Safety Assessment Application Guide, when changing maintenance rule performance criteria was acceptable because this methodology generally provides conservative results if applied correctly. As stated in Inspection Report 50-254/01-05; 50-265/01-05, the inspectors reviewed the EPRI guidance and had no concerns with the licensees application of the guidance. With regards to the failure to update the Probabilistic Risk Assessment Report every 2 years as required by procedure, NRR determined that no regulatory requirement existed that required an update to be made. However, should the licensee request a license amendment, a Notice of Enforcement Discretion, or some other relief from regulatory requirements using the existing Probabilistic Risk Assessment Report, the Nuclear Regulatory Commission would expect the licensee to provide an updated version of the Probabilistic Risk Assessment information. Lastly, the inspectors were concerned with the licensees decision not to establish condition monitoring criteria as discussed in Regulatory Guide 1.160. NRR determined that a licensees conformance to Regulatory Guide 1.160 was not required by regulations. Therefore, the licensees decision to not establish condition monitoring criteria was not a violation of regulatory requirements.
.2 (Closed) Unresolved Item 50-254/01-17-02; 50-265/01-17-02: This unresolved item involved the impact that the potential for lifting of standby liquid control system relief valves had on the licensees continued compliance with the Anticipated Transient Without Scram (ATWS) Rule, 10 CFR 50.62, and standby liquid control system operability as defined in Technical Specification 3.1.7. As stated in Inspection Report 50-254/01-17; 50-265/01-17, the inspectors discovered conflicting information regarding the licensees continued ability to comply with 10 CFR 50.62 and Technical Specification 3.1.7 due to the discovery that the standby liquid control system relief valves may lift during two pump operation required by the ATWS rule.
The conflicting information was provided to individuals in the Nuclear Regulatory Commissions Office of Nuclear Reactor Regulation for review. In December 2000 the NRC issued Regulatory Guide 1.186, Guidance and Examples for Identifying 10 CFR 50.2 Design Bases, which endorsed Appendix B to Nuclear Energy Institute (NEI) Document 97-04, Design Bases Program Guidelines. The general guidance in Appendix B to NEI 97-04 states that design basis functions are:
Functions performed by systems, structures and components that are (1) required by, or otherwise necessary to comply with, regulations, license conditions, orders or technical specifications, or (2) credited in the licensees safety analyses to meet NRC requirements.
Based on the above information, the NRCs position was that although the original Quad Cities design basis did not include ATWS events, these types of events must now be included. The inspectors also used the above information to determine that the lifting of the standby liquid control relief valves resulted in the licensee being outside of their design basis and in non-compliance with the ATWS rule since the system was unable to meet the required injection flow rate and boron concentration during the time the relief valves were lifting.
Part 50.62 to 10 CFR requires, in part, that each boiling water reactor must have a standby liquid control system with the capability of injecting into the reactor pressure 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 of 13 weight percent sodium pentaborate decahydrate (boron) solution. The failure to have a standby liquid control system with the capability of injecting into the reactor pressure 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 of 13 weight percent sodium pentaborate decahydrate (boron) solution was considered a Non-Cited Violation (NCV 50-254/02-05-05; 50-265/02-05-05) of 10 CFR Part 50.62. This issue was entered into the licensees corrective action program as Condition Report Q2001-02901.
The inspectors reviewed the risk significance of this issue and determined that the inability of the standby liquid control system to meet the requirements of the ATWS rule was more than minor because if left uncorrected, the issue would become a more significant safety concern and the issue affected the function of a system or train in a mitigating system. The inspectors screened the issue using the Significance Determination Process and determined the safety significance of this issue to be very low (Green) because the standby liquid control system could be recovered during an ATWS event, cycling of the relief valves would allow a portion of the borated solution to be injected into the reactor pressure vessel, and the licensee was able to demonstrate that they remained within the acceptance criteria of their original ATWS analyses even if no boron solution was injected into the reactor pressure vessel during the relief valve lifts.
The Office of Nuclear Reactor Regulation also determined that although the licensee was not in compliance with the ATWS rule due to the standby liquid control system relief valves lifting, the standby liquid control system remained operable per the requirements of Technical Specification 3.1.7. This determination was based upon information contained in NUREG-1433, Standard Technical Specifications General Electric Plants, which states that Technical Specification 3.1.7 does not require meeting the requirements of 10 CFR 50.62 to meet the associated Technical Specification Limiting
Condition for Operation. Based upon this information, no violation of Technical Specifications occurred.
4OA6 Meetings
.1 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 June 26, 2002. The licensee acknowledged the findings presented. No proprietary information was identified.
.2 Interim Exit Meeting Senior Official at Exit:
Mr. Timothy Tulon, Site Vice President Date:
April 12, 2002 Proprietary Information:
No Subject:
Radiological Access Control Program and the ALARA Planning and Controls Program
.3 Interim Exit Meeting Senior Official at Exit:
Mr. Timothy Tulon, Site Vice President Date:
April 12, 2002 Proprietary Information:
No Subject:
Physical Security 4OA7 Licensee Identified Violations The following violation of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements which met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.
Technical Specification 3.0.4 states that when a limiting condition for operation is not met, entry into a mode or other specified condition in the Applicability shall not be made except when the associated actions to be entered permit continued operation for an unlimited period of time. The Applicability section of Technical Specification 3.5.1, Emergency Core Cooling System - Operating, states that the HPCI system shall be operable in Mode 1 and Modes 2 and 3 when reactor vessel pressure is greater than 150 psig. On March 4, 2002, as described in LER 50-265/02-001-00, operations personnel increased reactor pressure above 150 psig with the HPCI turbine disconnected from the pump. The failure to ensure the HPCI system was operable prior to exceeding 150 psig reactor pressure was considered a Non-Cited Violation of Technical Specification 3.0.4 in accordance with Section VI.A.1 of the NRCs Enforcement Policy (NCV 50-265/02-05-02). This issue was included in the licensees corrective action program as Condition Report 101320.
The inspectors determined that the failure to have the HPCI turbine connected to the pump when reactor pressure was greater than 150 psig was more than minor because having an inoperable and unavailable mitigating system impacted safety. The inspectors evaluated this issue using a Significance Determination Process Phase 2 risk analysis. The inspectors determined the safety significance of this issue to be very low (Green) because the reactor was at low pressure and adequate mitigating equipment was operable or available.
PARTIAL LIST OF PERSONS CONTACTED Licensee T. Tulon, Site Vice President B. Swenson, Plant Manager D. Barker, Radiation Protection Manager W. Beck, Regulatory Assurance Manager G. Boerschig, Work Control Manager R. Gideon, Engineering Manager K. Hungerford, Wackenhut Project Manager A. Javorik, Maintenance Manager K. Leech, Security Manager K. Moser, Chemistry/Environ/Radwaste Manager M. Perito, Operations Manager M. Snow, Nuclear Oversight Manager NRC M. Ring, Chief, Reactor Projects Branch 1 ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-265/02-05-01 NCV Failure to Participate in Turnover Contributes to Manual Reactor Head Vent Isolation Valves Being Left Open During Unit Startup 50-265/02-05-02 NCV Failure to Have Unit 2 HPCI System Operable With Reactor Pressure Greater than 150 psig 50-254/02-05-03; NCV Failure to Perform Required Parts Evaluation for Control Rod 50-265/02-05-03 Drive Accumulator Clamps 50-265/02-05-04 FIN Inadequate Digital Feedwater System Design and Inadvertent Grounding of Plant Equipment Results in Reactor Scram 50-254/02-05-05; NCV Failure to Meet 10 CFR 50.62 due to Relief Valves Lifting 50-265/02-05-05
Closed 50-265/02-05-01 NCV Failure to Participate in Turnover Contributes to Manual Reactor Head Vent Isolation Valves Being Left Open During Unit Startup 50-265/02-05-02 NCV Failure to Have Unit 2 HPCI System Operable With Reactor Pressure Greater than 150 psig 50-254/02-05-03; NCV Failure to Perform Required Parts Evaluation for Control Rod 50-265/02-05-03 Drive Accumulator Clamps 50-265/02-05-04 FIN Inadequate Digital Feedwater System Design and Inadvertent Grounding of Plant Equipment Results in Reactor Scram 50-254/02-05-05; NCV Failure to Meet 10 CFR 50.62 due to Relief Valves Lifting 50-265/02-05-05 50-254/00-001-01 LER Automatic Reactor Scram from Low Reactor Vessel Level 50-254/00-002-01 LER Inadequate Calibration of Post Accident Torus Temperature Monitors 50-254/01-05-02; URI Methods for Changing Maintenance Rule Performance Criteria 50-265/01-05-02 50-254/01-17-02; URI Unexpected Lifting of Standby Liquid Control Relief Valves 50-265/01-17-02 50-265/02-001-00 LER High Pressure Coolant Injection System Uncoupled Above 150 psig due to Misapplication of Technical Specifications 50-254/02-002-00 LER Manual Scram due to Reactor Vessel Level Transient as a Result of Digital Feedwater Level Control System Design Error
LIST OF ACRONYMS AND INITIALISMS USED AA Access Authorization ALARA As-Low-As-Is-Reasonably-Achievable ATWS Anticipated Transient Without Scram CFR Code of Federal Regulations CR Condition Report DOT Department of Transportation EPRI Electric Power Research Institute HPCI High Pressure Coolant Injection LER Licensee Event Report mlb/hr Million Pounds per Hour MWe Megawatts Electric NEI Nuclear Energy Institute NRR Office of Nuclear Reactor Regulation psig Pounds per Square Inch Gauge
LIST OF DOCUMENTS REVIEWED 1R01 Adverse Weather QCOP 0010-10 Required Hot Weather Routines Revision 3 OP-AA-108-109 Seasonal Readiness Revision 0 Summer Readiness Action Matrix Seasonal Readiness Assessment Updated Final Safety Analysis Report QCOA 0010-10 Tornado, Thunderstorms and High Winds QCOP 3900-01 Service Water System Operation Revision 6 QCOP 1000-09 Torus Cooling System Startup and Operation Revision 15 System Engineering Seasonal Readiness Material Condition List List of Overdue Preventive Maintenance Tasks and Maintenance Items on Service Water and Torus Cooling Systems 1R04 Equipment Alignment QCOP 6600-04 Diesel Generator 1/2 Preparation for Standby Operation Revision 20 QCOP 1300-1 Reactor Core Isolation Cooling System Preparation for Standby Operation Revision 20 QCOP 2300-01 High Pressure Coolant Injection System Preparation for Standby Operation Revision 31 1R05 Fire Protection Quad Cities Units 1 and 2 Updated Fire Hazards Analysis Revision 13 QCAP 1500-1 Administrative Requirements Fire Protection Revision 14 Quad Cities Pre-Fire Plans Revision 11 QCMMS 4100-71 Fire Extinguisher Inspection Revision 7 QCIS 4100-40 Unit 1 Reactor Building (El. 623 ft.) Fire Protection Functional Test Revision 1
Work Order 99211567-01 Reactor Building Fire Protection Functional Test August 28, 2001 Work Order 99247251-01 Perform Fire Extinguisher Annual Inspection of the Reactor Building December 7, 2001 Condition Report 092971 Station Fire Extinguishers Exceeding their Hydro Due Dates January 31, 2002 Condition Report 108416 Potential Administrative Error in QCIS 4100-40 May 16, 2002 1R06 Flood Protection Measures QCOA 0010-16 Flood Emergency Procedure Revision 8 QCAP 0250-06 Control of In-Plant Watertight Submarine Doors Revision 6 Quad Cities Special Report 3 October 16, 1972 Quad Cities Special Report 3A November 7, 1972 Quad Cities Special Report 3B April 7, 1973 QCTS 810-01 Reactor Building Internal Flood Barriers Surveillance Revision 2 QCTS 820-01 Leak Test of the RHR Service Water Vault Flood Protection Penetrations Revision 7 QCTS 820-02 Leak Test of the RHR Service Water Vault Flood Protection Bulkhead Doors Revision 6 QCTS 820-03 Leak Test of the RHR Service Water Vault Flood Protection Watertight Doors Revision 6 QCTS 820-10 RHR Service Water Vault Sump Discharge Check Valve Test Revision 5 QCMPM 1500-02 RHR Service Water Submarine Door Preventive Maintenance Revision 5 QCMPM 1500-03 Reactor Building Basement Submarine Door Preventive Maintenance Revision 5 Condition Report 00094142 Watertight Sub Door Found Open February 7, 2002 Condition Report 00094747 Admin Procedure Directs Plugging Floor Drains February 11, 2002 Condition Report 00094761 Unit 2 Condensate Pump Room Approximately 6 Inches of Water on Floor February 16, 2002
Condition Report 00093609 Plant Tour February 2, 2002 Condition Report 00093012 Inconsistencies in UFSAR Sec 3.4.1.2.1 RHRSW Vault Flood Protection January 28, 2002 1R11 Operator Licensing Requalification Operating Exam Number Three Guide Main Steam Line Flow Instrument Failure/Large Loss Of Coolant Accident/Reactor Pressure Vessel Flooding Revision 17 QGA 100 Reactor Pressure Vessel Control Revision 7 QGA 200 Primary Containment Control Revision 8 QGA 500-1 Reactor Pressure Vessel Blowdown Revision 11 EP-AA-111 Emergency Classification and Protective Action Recommendations Revision 3 1R12 Maintenance Rule Implementation Maintenance Rule Data Package for Automatic Depressurization System (Valves and logic)
April 2002 Condition Report 96900 Performance of Automatic Depressurization System Logic Test February 26, 2002 Condition Report 99577 Unit 2 125 Volt Battery Ground March 16, 2002 Maintenance Rule Data Package for Reactor Protection System April 2002 Condition Report 96885 Full SCRAM from IRM 16 February 26, 2002 Condition Report 97046 Inadvertent 1/2 SCRAM February 27, 2002 Condition Report 96900 Received B Channel 1/2 SCRAM February 25, 2002 Condition Report 96900 RPS 1/2 SCRAM from LPRM February 24, 2002 Maintenance Rule Data Package for Division II Alternating Current April 2002
1R13 Maintenance Risk Assessment and Emergent Work Evaluation Work Week Safety Profile Week of April 06, 2002 Work Week Safety Profile Week of April 13, 2002 Work Week Safety Profile Week of April 27, 2002 Work Week Safety Profile Week of May 4, 2002 Work Week Safety Profile Week of May 13, 2002 Work Week Safety Profile Week of May 20, 2002 Daily Production Plan Of The Day Week of April 06, 2002 Daily Production Plan Of The Day Week of April 13, 2002 Daily Production Plan Of The Day Week of April 27, 2002 Daily Production Plan Of The Day Week of May 4, 2002 Daily Production Plan of The Day Week of May 13, 2002 Daily Production Plan of The Day Week of May 20, 2002 WC-AA-103 On-Line Maintenance Revision 4 1R14 Personnel Performance During Nonroutine Plant Evolutions Condition Report 101320 HPCI Uncoupled with Reactor Pressure Greater than 150 psig March 28, 2002 Prompt Investigation Report for Condition Report 101320 Unit 2 HPCI Turbine was Left Uncoupled and Reactor Pressure was Raised Above 150 psig March 28, 2002
Root Cause Investigation Report for Condition Report 101320 High Pressure Coolant Injection System was not Operable when Required due to Operations Misunderstanding and Misapplication of Technical Specifications April 25, 2002 Condition Report 97694 Unit 2 Reactor Head Vent Bypass Valves Found Open March 4, 2002 Condition Report 110590 Readdress Apparent Cause Evaluation for Condition Report 91694 June 4, 2002 Condition Report 112360 NRC Identifies Issue With Apparent Cause/Corrective Actions for Manual Head Vents June 19, 2002 OP-AA-112-101 Shift Turnover and Relief Revision 0 HU-AA-104-101 Procedure Use and Adherence Revision 0 OP-AA-108-102 Equipment Status Tags Revision 0 QCOS 0201-08 Reactor Vessel and Class One Piping Leak Test Revision 27 Condition Report 111065 Reactor Pressure Made a Step Drop from 1002#
to 999#
June 7, 2002 Available Unit 2 Plant Data June 7, 2002 Unit 2 Reactor Operator Logs June 7-9, June 18, and June 20, 2002 Condition Report 111976 Unexpected Change in Unit 2 Parameters June 17, 2002 Operability Evaluation for Condition Report 111976 Unit 2 Steam Dryer Problems June 19, 2002 Condition Report 112294 Level, Pressure, and MWe Transient June 18, 2002 Unit 2 Reactor Operator Logs and Plant Data June 18, 2002 1R15 Operability Evaluations Action Request 98960-08 1A RHR Heat Exchanger Operability Documentation March 13, 2002 Condition Report 102235 Gland Seal Water to Unit 1 EDG April 3, 2002
Problem Identification Form Q1998-01025 Operability Determination for work on U1 EDG March 20, 1998 Quad Cities Data Request Form 3086 EDG Cooling Water Pump Seals August 26, 1993 Condition Report 98263 Hydraulic Control Units Restraining Band Clamps March 7, 2002 Engineering Evaluation Control Rod Drive Accumulator Missing Strap Evaluation April 2, 2002 Condition Report 105454 General Electric Part 21 Notification SC 02-05 April 26, 2002 Condition Report 107669 Ineffective Corrective Action for NON DR-01-060 Unknown Operability Evaluation for Condition Report 105454 General Electric CR105X Auxiliary Contacts May 10, 2002 10 CFR Part 21 Notification Failure of CR105X Auxiliary Contacts April 23, 2002 General Electric Service Advisory Letter 2.1 CR105X Auxiliary Interlock Malfunction - Nuclear Power Stations August 2, 1978 Dresden Station Operability Evaluation 02-004 General Electric CR105X Auxiliary Contacts on Size 1 Contactors February 8, 2002 Operability Evaluation for Condition Report 111976-09 Moisture Carryover Preliminary Analysis - Quad Cities Unit 2 June 18, 2002 1R19 Post-Maintenance Testing Work Order 00395688 U2 #3 Power Operated Relief Valve Replacement February 12, 2002 Quality Receipt Inspection Package for Power Operated Relief Valve December 21, 2001 Work Order 00423819 U2 #3 Power Operated Relief Valve Replacement March 29, 2002
QCOS 0010-08 High Radiation Area Inspection Guidelines Revision 2 QCOS 0201-12 Class One ASME Section XI Post Replacement Pressure Test At Power Operation Revision 2 QCOS 0005-04 IST Valve Position Indication Surveillance Revision 8 QCOS 1600-31 Suppression Pool Water Temperature Monitoring Revision 4 QCOS 0203-03 Main Steam Relief Valves Operability Test Revision 18 Work Order 00379753 1/2 Diesel Generator Lube Oil Circulating Pump March 27, 2002 Work Order 00363309 1/2 Diesel Generator Local Tachometer March 20, 2002 Work Order 00395531 1/2 Diesel Generator Starting Air Strainer March 19, 2002 Work Order 00418906 1/2 Diesel Generator Timing Relays March 20, 2002 QCOS 6600-43 Unit 1/2 Diesel Generator Load Test Revision 9 Work Order 9927921801 Replace 125 VDC Breaker for HPCI Logic System Control Power February 24, 2002 Work Order 0041049301 U1 HPCI Steam Chest Hold Down Bolts March 27, 2002 Work Order 9915729901 1-2301-22 16" Gate Valve Overhaul March 27, 2002 Work Order 9926231301 HPCI Flow Controller FIC 1-2340-01 Dynamic calibration March 19, 2002 QCOS 2300-05 Quarterly HPCI Pump Operability Test Revision 44 Work Order 00452432-07 U1 Repair Pinhole Leak on Pump Discharge Piping - 1B RHRSW June 13, 2002 QCOS 1000-04 RHR Service Water Pump Operability Test Revision 30 1R22 Surveillance Testing QCIS 0700-22 Unit 1 Division II Power Operation APRM Functional Test Revision 0 QCOS 1400-08 Core Spray System Power Operated Valve Test Revision 14
QCOS 6600-41 Unit 1 Diesel Generator Load Test Revision 10 QCOS 6600-42 Unit 2 Diesel Generator Load Test Revision 10 QCOS 6600-03 Diesel Fuel Oil Transfer Pump Monthly Operability Revision 14 QCOS 6600-02 Diesel Generator Air Compressor Operability Revision 15 QCOS 0203-07 Automatic Blowdown Logic Test Revision 5 CY-QC-120-600 Off-Gas Sampling Revision 3 CY-QC-130-401 Off-Gas Isotopic Analyses Recombiner Outlet and Adsorber Inlet Samples Revision 1 QCOS 1600-45 Unit 2 Primary Containment Isolation Group 3 Test Revision 2 QCOS-1000-06 Residual Heat Removal/LOOP Operability Test Revision 28 1R23 Temporary Plant Modifications Work Order 414436 Install Steel Cap on 2-0220-57A Valve April 29, 2002 Engineering Change 336058 ASME Section XI Code Reconciliation April 29, 2002 Design Analysis02-007 Stress Report for Valve 2-0220-57A and Cover April 29, 2002 Design Analysis Q2-FW-02C/Analysis Evaluation of Temporary Modification of Valve 2-0220-57A April 28, 2002 1EP4 Emergency Action Level and Emergency Plan Changes Quad Cities Nuclear Power Station Annex to the Exelon Nuclear Standardized Radiological Emergency Plan Revision 14 1EP6 Drill Evaluation LOCT-1002 EPU Loss of Coolant Accident/Loss of Normal Feedwater Revision 0 QGA 100 Reactor Pressure Vessel Control Revision 7 QGA 200 Primary Containment Control Revision 8 QGA 300 Secondary Containment Control Revision 11
EP-AA-111 Emergency Classification and Protective Action Recommendations Revision 3 Scenario for April 19, 2002, Emergency Preparedness Drill Nuclear Accident Reporting System and Emergency Notification System Forms from April 19, 2002 Emergency Preparedness Drill April 19, 2002 Scenario for June 12, 2002, Emergency Preparedness Pre-Exercise Nuclear Accident Reporting System and Emergency Notification System Forms from June 12, 2002 Emergency Preparedness Pre-Exercise June 12, 2002 NEI 99-02, Revision 2 Regulatory Assessment Performance Indicator Guideline November 2001 2OS1 Access Control LS-AA-125 Corrective Action Program (CAP) Procedure Revision 2 QCFHP 0500-01 Spent Fuel Storage Pool Inventory Control and Audit Revision 4 Nuclear Oversight: NOA-QC-01-4Q January 30, 2002 Focus Area Self-Assessment: ALARA Planning and Controls January 14-21, 2002 55511-35 N.O. Field Observation: Observed Work in Progress August 7, 2001 55511-34 N.O. Field Observation: Observed Work in Progress August 12, 2001 55511-55 N.O. Field Observation: Observed Work in Progress August 31, 2001 55511-43 N.O. Field Observation: Observed Work in Progress September 18, 2001 55511-41 N.O. Field Observation: Work Practices September 20, 2001 55511-54 N.O. Field Observation: ALARA Program September 24, 2001 88678-08 N.O. Field Observation: Radiation Postings, Labeling and Calibration January 4, 2002
88678-09 N.O. Field Observation: Radiation Postings, Labeling and Calibration January 9, 2002 88678-11 N.O. Field Observation: U1 Drywell Access Control Point January 19, 2002 88678-36 N.O. Field Observation: Radiation Postings, Labeling and Calibration February 13, 2002 88678-52 N.O. Field Observation: Dosimetry Placement February 27, 2002 88678-27 N.O. Field Observation: U2 Drywell Access Control Point February 27, 2002 88678-46 N.O. Field Observation: Radiation Postings After U2 Start Up March 6, 2002 88678-50 N.O. Field Observation: RP Programs-Internal Dose Control March 14, 2002 88678-56 N.O. Field Observation: Source Term Reduction March 27, 2002 97378 Increased Dose Rates in Reactor Cavity Post Drain Down March 1, 2002 95481 Higher Than Expected Dose Rates Identified in the D Heater Bay February 15, 2002 96664 IDNS Inspector Identifies Radworker Issues February 21, 2002 97884 Grit Blasting Turbine Component Without RP Coverage March 5, 2002 98886 Offgas Leak Outside of the 2A Recombiner March 12, 2002 95715 Personnel Contamination Event February 17, 2002 96430 Poor Radworker Practice at CRD Repair Room February 23, 2002 97547 Refuel Floor Worker Contaminated March 2, 2002 97871 Packing Leak: Unplanned Spread of Contamination March 5, 2002 95707 Steam Dryer Underwater Brushing Increases Contact Dose Rates February 19, 2002 95523 Unplanned Spread of Contamination U2 Torus Area February 16, 2002 98823 Unplanned Spread of Contamination March 12, 2002 98930 U2 RWCU Valve Room Elevated Dose Rates March 13, 2002
94259 Unplanned Spread of Contamination February 7, 2002 100363 Unplanned Spread of Contamination Outside of the 1A CS Room March 21, 2002 100312 Unplanned Spread of Contamination U2 RB 623 March 21, 2002 101745 Unplanned Spread of Contamination U2 623 March 31, 2002 102737 RP Shielding Questions for Equipment After LCO Started April 8, 2002 100374 NOS Identified Problems With Documentation for Contamination Events January 11, 2002 98258 NOS Identified Survey Not Revised For Dosimetry Placement February 27, 2002 2OS2 ALARA Planning and Controls RP-AA-400 ALARA Program Revision 2 RP-AA-401 Operational ALARA Planning and Controls Revision 2 WC-AA-101-1002 On Line Scheduling Process Revision 0 RP-AA-270 Prenatal and Postnatal Programs Revision 1 10001166 RWP/ALARA Plan: 1B Recirc Pump Motor, Remove/Replace Motor and Interferences (Q1F49)
January 19, 2002 10001154 RWP/ALARA Plan: 1B Recirc Pump, Removal/Install Pump Internals (Q1F49)
January 20, 2002 10001135 RWP/ALARA Plan: U1 Reactor Disassembly/Reassembly, Cavity Work and Wall Cleaning (Q1F49)
January 10, 2002 10000326 RWP/ALARA Plan: U2 EPU Mod, Uprate of RFW Heater Shells/Nozzles (Q2R16)
December 19, 2001 10000220 RWP/ALARA Plan: U2 Drywell Shielding Activities (Q2R16)
December 19, 2001 10000233 RWP/ALARA Plan: U2 CRDs (24),
Unlatch/Remove/Replace (Q2R16)
January 19, 2002 Source Term Reduction Plan (Draft)
2002 2PS2 Transportation of Radioactive Materials Uniform Low-Level Radioactive Waste Manifest April 9, 2002
3PP Physical Protection SY-AA-101-112 Searching Personnel and Packages Revision 5 SY-AA-101-122 Testing Security Equipment Revision 5 SY-AA-101-123 Searching Vehicles and Cargo/Material Revision 6 SY-AA-101-120 Control of Security Keys and Cores Revision 1 SY-AA-102 Exelons Nuclear Fitness for Duty Program Revision 5 SY-AA-103-511 Request for Unescorted Access Revision 7 SY-AA-103-512 Continual Behavioral Observation Program Revision 3 SY-AA-103-514 Fabrication of Security Badges Revision 6 TQ-AA-118 Nuclear General Employee Training - N-GET Revision 3 Security 3rd Quarter 2001 Focus Area Self-Assessment Report Security Equipment Testing (AR# 43391-03, Security Training Program July - September 2001 Security Event Logs October 2000 -
September 2001 Security Incident Reports July 2001 - March 2002 Security Work Requests July 2001 - March 2002 Nuclear Oversight Continuous Assessment Report NOA-QC-01-4Q Security Assessment October - December 2001 Security Focus Area Self-Assessment Report Vehicle Search April 2 - June 30, 2001 Security Focus Area Self-Assessment Report Security Ingress/ Access Control October - December 2001
Security Focus Area Self-Assessment Report NRC Audit Preparation - Access Authorization, Access Control, Security Plan Changes, and Performance Indicator Data October 2001 -
January 2002 Security Focus Area Self-Assessment Report Safeguards Controls February 12-28, 2002 4OA1 Performance Indicator Verification Unit 1 Operator Logs July 2001 - March 2002 Unit 2 Operator Logs July 2001 - March 2002 LS-AA-2010 Monthly Performance Indicator Data Elements for Unplanned SCRAMS for 7000 Critical Hours July 2001 - March 2002 LS-AA-2020 Monthly Performance Indicator Data Elements for SCRAMS with a Loss of Normal Heat Removal July 2001 - March 2002 Quad Cities Monthly Operating Reports July 2001 -
May 2002 LS-AA-2030 Monthly Performance Indicator Data Elements for Unplanned Power Changes per 7000 Critical Hours July 2001 -
May 2002 NRC Inspection Reports July 2001 - March 2002 4OA2 Identification and Resolution of Problems Condition Report 79779 Incorrect Injectors Installed During QCMMS 6620-05 October 2, 2001 Condition Report 89176 Unplanned Technical Specification Limiting Condition for Operation Entry January 7, 2002 Condition Report 89499 Mechanics Start to Breach Wrong Valve January 7, 2002 Condition Report 89830 Chemistry Department Event Free Clock Resets January 10, 2002 Condition Report 90267 Plastic Protractor Missing Off Ultrasonic Testing Fixture in Vessel January 13, 2002
Condition Report 91162 Incorrect Jet Pump Beam Detensioned due to Identification Error January 17, 2002 Condition Report 91235 1A Recirculation Pump Motor Bearing Oil Inadvertently Changed January 18, 2002 Condition Report 92250 2B Control Rod Drive Pump Catastrophic Failure January 24, 2002 Condition Report 92430 Station Human Performance Issues in January 2002 January 25, 2002 Condition Report 92943 Normally Closed Valve Found Throttled Open and Damaged January 29, 2002 Condition Report 94142 Watertight Submarine Door Found Open February 7, 2002 Condition Report 94249 1B Reactor Recirculation Pump Trip February 7, 2002 Condition Report 95097 Safety Relief Valves 4B and 4E Rams Heads Installed in the Incorrect Position February 14, 2002 Condition Report 95152 1A Offgas Hydrogen Analyzer Exceeded Surveillance Frequency February 13, 2002 Condition Report 95467 Working on System Without Clearance Order February 15, 2002 Condition Report 95532 Removed Limitorque from 2-220-2 with Out of Service Card on Handwheel February 17, 2002 Condition Report 95542 Hydrogen Deflagration in Condensate System During Welding February 17, 2002 Condition Report 96155 Unit 1 D Heaters Tripped at Full Power February 25, 2002 Condition Report 96875 Near Miss While Filling Main Condenser February 26, 2002 Condition Report 96890 Unexpected Auto Start of 2A Core Spray Pump February 26, 2002 Condition Report 97694 Unit 2 Reactor Head Vent Bypass Valves Found Open March 4, 2002 Condition Report 98256 2B Condensate Pump Outboard Seal Failure due to Foreign Material March 7, 2002 Condition Report 99953 Plugs Installed on Unit 2 Feedwater Heaters C and D Relief Valve Vents February 25, 2002
Condition Report 100473 Incorrect Availability Call for Unit 1 HPCI Turning Gear Logic Test March 21, 2002 Condition Report 101320 Unit 2 HPCI Turbine was left Uncoupled and Reactor Pressure was Raised Above 150 psig March 28, 2002 Condition Report 102589 Manual Reactor Scram on Increasing Reactor Pressure Vessel Level due to Inadequate Original Design of the Digital Feedwater System April 5, 2002 Condition Report 107804 Unit 2 Valves Operated During Unit 1 Residual Heat Removal Timing Surveillance May 13, 2002 Condition Report 108873 Incorrect Transformer Cooling Fan Identified for Maintenance April 22, 2002 Condition Report 111114 Transformer T2 Deluge was Activated During Fire Protection Surveillance June 8, 2002 4OA3 Event Followup QCOA 0201-08 Reactor High Water Level Revision 14 QCGP 2-3 Reactor SCRAM Revision 40 QGA 100 RPV Control Revision 7 Condition Report 102589 Prompt Investigation of Unit 2 SCRAM April 5, 2002 Licensee Event Report 50-254/00-001 Automatic Reactor Scram from Low Reactor Vessel Level Revision 1 Licensee Event Report 50-254/00-002 Inadequate Calibration of Post Accident Torus Temperature Monitors Revision 1 Licensee Event Report 50-265/02-001 High Pressure Coolant Injection System Uncoupled Above 150 psig due to Misapplication of Technical Specifications Revision 0 Licensee Event Report 50-265/02-002 Manual Scram due to Reactor Vessel Level Transient as a Result of a Digital Feedwater Level Control System Design Error Revision 0 4OA5 Other Task Interface Agreement 2001-
Response to Task Interface Agreement 2001-07 From Region III Regarding Quad Cities Maintenance Rule Issues May 1, 2002
Task Interface Agreement 2001-
Response to Task Interface Agreement 2001-12 Regarding Susquehanna Steam Electric Plant, Units 1 and 2, Design and Licensing Basis for the Standby Liquid Control System May 6, 2002