IR 05000254/2002004
| ML021070149 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 04/15/2002 |
| From: | Ring M NRC/RGN-III/DRP/RPB1 |
| To: | Skolds J Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-02-004 | |
| Download: ML021070149 (35) | |
Text
ril 15, 2002
SUBJECT:
QUAD CITIES NUCLEAR POWER STATION NRC INTEGRATED INSPECTION REPORT 50-254/02-04; 50-265/02-04
Dear Mr. Skolds:
On March 31, 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 April 2, 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 three issues of very low safety significance (Green). Two 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 Violation, 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 20555-001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; and the NRC Resident Inspector at the Quad Cities Nuclear Power Station. 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 50-254/02-04, 50-265/02-04
REGION III==
Docket Nos: 50-254; 50-265 License Nos: DPR-29; DPR-30 Report No: 50-254/02-04, 50-265/02-04 Licensee: Exelon Nuclear Facility: Quad Cities Nuclear Power Station, Units 1 and 2 Location: 22710 206th Avenue North Cordova, IL 61242 Dates: February 11 - March 31, 2002 Inspectors: K. Stoedter, Senior Resident Inspector G. Wilson, Acting Senior Resident Inspector J. Adams, Resident Inspector S. Campbell, Senior Resident Inspector - Fermi J. House, Senior Radiation Specialist D. Jones, Reactor Engineer R. Lerch, Project Engineer P. Pelke, Reactor Engineer S. Sheldon, Engineering Inspector Approved by: Mark Ring, Chief Branch 1 Division of Reactor Projects
SUMMARY OF FINDINGS IR 05000254-02-04, IR 05000265-02-04 on 02/11 - 03/31/2002, Exelon Nuclear, Quad Cities Nuclear Power Station, Units 1 & 2, non-routine plant evolutions, surveillance testing, and event follow-up.
The inspection was conducted by resident and regional inspectors. This inspection identified three Green issues, two of which 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/index.html.
A. Inspector Identified Findings Cornerstone: Mitigating Systems Green. On January 24, 2002, a catastrophic failure of the 2B control rod drive pump occurred approximately 4 days after conducting maintenance. The pump failure was caused by the inadequate lubrication of the inboard pump bearing due to the inappropriate setting of a constant level oiler. The root cause was that the constant level oiler was set approximately 15/64 of an inch lower than the specified setting due to maintenance personnel using a previously painted oil level reference line on the pump casing rather than a more exact installation method. No violations of NRC requirements were identified as a result of this event due to the control rod drive system being non-safety related.
The finding was of very low safety significance. Although the finding represented an actual loss of safety function of one train of non-Technical Specification equipment designated as risk significant by the maintenance rule for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, all remaining mitigating equipment remained available to respond to potential transients (Section 1R14).
Green. The inspectors identified a Non-Cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, for the failure to determine the cause of a 1995 2A standby liquid control pump trip and take corrective actions to preclude repetition. On February 15, 2002, during surveillance test actuations of the standby liquid control system explosive valves, the continuity of the firing circuit remained intact. Fragments contacted the standby liquid control system piping creating a circuit path to ground. The existence of a previously unidentified independent ground at a different point in the control circuitry created a condition where the voltage was not adequate to support continued system operation and the 2A standby liquid control pump tripped. The 2A standby liquid control pump tripped during the performance of the same surveillance procedure in 1995. Following the February 2002 pump failure, the licensee determined that troubleshooting performed in 1995 was inadequate in that it failed to identify the actual cause of the pump trip.
The finding was of very low safety significance because the 2B train of the standby liquid control system was unaffected by this issue and all remaining mitigating equipment was available to respond to an anticipated transient without scram event (Section 1R22).
Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III for failure to establish measures to assure that items such as thermal effects and the compatibility of materials were correctly translated into specifications for the Unit 2 emergency diesel generator fuel oil transfer system. On May 1, 2001, and May 3, 2001, a solenoid valve in the Unit 2 emergency diesel generator fuel oil transfer system failed to open approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the start of the emergency diesel generator 24-hour endurance test. The solenoid valve failure was due to thermal pressurization of an isolated section of fuel oil transfer system discharge piping.
The finding was of very low safety significance because the Unit 2 station blackout diesel generator was not impacted by this design issue, actions to manually fill the fuel oil day tank were proceduralized such that recovery of the emergency diesel generator should be successful, and alternative mitigating equipment was available to respond to a potential loss of offsite power. (Section 4OA3).
B. Licensee Identified Findings No findings of significance were identified.
Report Details 1. REACTOR SAFETY Plant Status Unit 1 began the inspection period operating at 100 percent power. Operations personnel reduced reactor power on February 17 to accomplish control rod maneuvers and returned the reactor to full power later the same day. On February 21, Unit 1 experienced an unexpected power reduction from approximately 820 megawatts electric (MWe) to 420 MWe due to a feedwater heater transient associated with maintenance on the desuperheat flow control valve. Once operations and maintenance personnel understood the cause of the feedwater heater transient, control room personnel returned the unit to full power where it operated for the remainder of the period.
Unit 2 began the inspection period operating at 92.3 percent power and in coast down for a scheduled refueling outage. On February 12, 2002, operations personnel shut down Unit 2 for a refueling outage. Major activities scheduled during the outage included required local leak rate testing, a 10 year overhaul on the high pressure coolant injection system, installation of a digital feedwater control system, replacement of the Yarway reactor vessel level instrumentation, and implementation of extended power uprate modifications. Unit 2 entered Mode 2 on March 4, 2002. Operations personnel synched the generator with the offsite electrical distribution system on March 5. Between March 6 and 14, operations and engineering personnel conducted power ascension testing for the extended power uprate. Following this testing, Unit 2 achieved a new power level of 912 MWe or 95.8 percent of the new licensed power level. Unit 2 was unable to achieve 100 percent of the new licensed power level due to limitations on the main generator. On March 29 operators conducted a reactor shutdown to repair leaks on the turbine electro-hydraulic control system for the number 1 and number 3 turbine control valves, leakage on the 2-0220-57A feedwater isolation valve, and a ground on the 3E power-operated relief valve. Unit 2 entered cold shutdown (Mode 4) on March 30. Unit 2 ended the period in cold shutdown.
1R04 Equipment Alignments (71111.04)
.1 Quarterly Equipment Alignments a. Inspection Scope The inspectors verified the system alignment of the following mitigating systems during the period:
Train Inspected Date Inspected Redundant Train Unavailable safe shutdown March 8, 2002 Unit 2 reactor core isolation makeup pump cooling Unit 1/2B standby gas March 12, 2002 Unit 1/2A standby gas treatment treatment Unit 2A core spray March 14, 2002 Unit 2B core spray Unit 1B core spray March 18, 2002 Unit 1A core spray 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.
.2 Semi-Annual Equipment Alignments a. Inspection Scope The inspectors performed the semi-annual system alignment of the Unit 1 125 volt direct current (Vdc) and 250 Vdc systems under the mitigating systems cornerstone. During walkdowns of the accessible portions of the systems, the inspectors compared the as-found configuration of the systems to the configuration specified in the respective Quad Cities operating procedures and drawings. 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)
.1 Quarterly Fire Zone Walkdowns a. Inspection Scope The inspectors conducted fire protection walkdowns of the ground floor of the Unit 1 Reactor Building (Fire Zone 1.1.12) and reviewed an issue associated with four sprinkler heads blocked by scaffolding in the cable spreading room. Both of these areas contained equipment related to the mitigating systems cornerstone. These inspections verified the proper control of transient combustibles and ignition sources, the material condition of fire detection and suppression systems, the operational lineup of fire detection and suppression systems, the maintenance of fire protection equipment, and the material condition and operational status of fire barriers. The inspectors also discussed issues associated with each fire zone with the fire marshall, fire protection engineering, and the licensees probabilistic risk assessment expert.
b. Findings No findings of significance were identified.
.2 Annual Fire Drill Observation a. Inspection Scope On March 26, 2002, the inspectors observed the fire brigade respond to a simulated fire in Fire Zone SC 61 (Old Construction Building) to evaluate the readiness of licensee personnel to prevent and fight fires.
b. Findings No findings of significance were identified.
1R08 Unit 2 Inservice Inspection Activities (71111.08)
a. Inspection Scope The inspectors conducted a review of the licensees implementation of their inservice inspection program for monitoring degradation of the reactor coolant system boundary
and the risk significant piping system boundaries. Specifically, the inspectors conducted a record review of the following examinations:
WELD # CONFIGURATION NDE TYPE N2F IRS Vessel-Nozzle Weld UT RPV-CW-C4FLG RPV Course #4 to Flange Weld UT RPV-THHF RPV Top Head to Flange Weld UT/MT 30A-S10 MS Elbow-Pipe Weld UT These examinations were evaluated for compliance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements. The inspectors also reviewed inservice inspection procedures, equipment certifications, personnel certifications, and NIS-2 forms for Code repairs performed during the last outage to confirm that ASME Code requirements were met.
A sample of inservice inspection related problems documented in the licensees corrective action program, was also reviewed to assess conformance with 10 CFR Part 50 Appendix B, Criterion XVI, Corrective Action, requirements. In addition, the inspectors determined that operating experience was correctly assessed for applicability by the inservice inspection group.
b. Findings No findings of significance were identified.
1R12 Maintenance Rule Implementation (71111.12Q)
a. Inspection Scope The inspectors reviewed the licensees implementation of the maintenance rule requirements, including a review of scoping, goal-setting, and performance monitoring, short-term and long-term corrective actions, and current equipment performance status.
The systems selected for inspection were all classified as risk significant by the licensees maintenance rule program. The systems evaluated were:
System Date Inspected Core Spray System February 12, 2002 Emergency Core Cooling System Room Coolers February 12, 2002 (core spray rooms only)
Primary Containment Isolation March 01, 2002 Emergency Core Cooling System Room Coolers March 11, 2002 (2A RHR room only)
Turbine Building Closed Loop Cooling Water March 26, 2002 (TBCCW)
The inspectors independently verified the licensees implementation of maintenance rule requirements for these systems by verifying that these systems were properly scoped within the maintenance rule; that all failed structures, systems, or components (SSCs)
were properly categorized and classified as (a)(1) or (a)(2); that performance criteria for SSCs classified as (a)(2) were appropriate; and that the goals and corrective actions for SSCs classified as (a)(1) were appropriate. The inspectors also verified that issues were identified at an appropriate threshold and entered in the corrective action program.
b. Findings No findings of significance were identified.
1R13 Maintenance Risk and Emergent Work (71111.13)
a. Inspection Scope The inspectors evaluated risk considerations for planned work on the simultaneous unavailability of the following systems:
Affected Systems Week Ending 1/2A standby gas treatment system, 4160 Volt busses 24 February 23, 2002 and 24-1, and transformer 22 1A core spray, safe shutdown makeup pump, Unit 1 March 23, 2002 high pressure coolant injection system, and oil circuit breaker 9-10 The inspectors assessed the operability of redundant train equipment and verified that the licensees planning of the maintenance activities minimized the length of time that the plant was subject to increased online and shutdown risk. The inspectors interviewed operations and work control department personnel to ensure that risk of the planned work was assessed in accordance with Nuclear Station Procedures WC-AA-103, On-Line Maintenance, and OU-AA-103, Shutdown Safety Management Program.
b. Findings No findings of significance were identified.
1R14 Nonroutine Plant Evolutions (71111.14)
.1 Catastrophic Failure of 2B Control Rod Drive Pump a. Inspection Scope On January 24, 2002, the licensee experienced a catastrophic failure of the 2B control rod drive pump approximately 4 days after conducting maintenance. The inspectors reviewed the appropriateness of operator actions to the failure, inspected damage to the
control rod drive system due to the failure, interviewed maintenance personnel, and reviewed the licensees root cause report and corrective actions for this issue.
b. Findings One Green finding was identified for the failure to properly set a constant level oiler which resulted in the catastrophic pump failure. The licensee identified extensive damage to the inboard pump bearing and housing, the pump and speed reducer shafts, the interconnecting coupling assembly, and surrounding components. The licensee determined that the pump failure was caused by the inadequate lubrication of the inboard pump bearing due to the inappropriate setting of a constant level oiler. The root cause investigators determined that the constant level oiler was set approximately 15/64 of an inch lower than the specified setting due to maintenance personnel using a previously painted oil level reference line on the pump casing rather than a more exact installation method.
The inspectors determined that inappropriate setting of constant level oilers was more than minor because, if left uncorrected, the same issue under the same conditions may become more of a safety concern because multiple risk significant pumps utilize constant level oilers for bearing lubrication. In addition, this issue affected the operability, availability, reliability, and function of a train in a mitigating system. The inspectors screened the issue using the Significance Determination Process and determined the risk significance of this issue to be very low (Green). Although the finding represented an actual loss of safety function of one train of non-Technical Specification equipment designated as risk significant by the maintenance rule for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, all remaining mitigating equipment remained available to respond to potential transients (FIN 50-265/02-04-01). Corrective actions for this finding included the verification of settings for all other constant level oilers in the plant, the use of laser alignment equipment when setting constant level oilers when possible, training on the acceptable methods for setting constant level oilers, and the incorporation of additional information on constant level oiler installation into maintenance work instructions. No violations of NRC requirements were identified as a result of this event due to the control rod drive system being non-safety related.
.2 Unexpected Unit 2 Power Reduction due to a leak on the Electro-Hydraulic Control Accumulator for the Number 1 Turbine Control Valve a. Inspection Scope On March 29, 2002, the licensee experienced an electro-hydraulic control leak on Unit 2 from the accumulator flange and associated piping on the number 1 turbine control valve.
The leak resulted in the reduction of thermal power to 24 percent due to Power Distribution Limit Technical Specification 3.2.2 Minimum Critical Power Ratio. The inspectors reviewed the appropriateness of operator actions to the failure, reviewed operator logs, evaluated damage to the electro-hydraulic control system due to the failure, interviewed operations personnel, and reviewed the licensees corrective actions for this issue.
b. Findings No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope The inspectors reviewed the operability evaluation associated with the inlet piping for the 2B and 2D residual heat removal service water system being below the design minimum wall thickness. A list of documents reviewed by the inspectors can be found in the List of Documents Reviewed section of this report.
The inspectors verified that operability evaluation was performed when required and that the completed evaluation was 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.
1R16 Operator Workarounds (71111.16)
Operator Workarounds - Cumulative Effects Assessment a. Inspection Scope The inspectors reviewed the cumulative effects of all documented operator workarounds and operator challenges on reliability, availability, and potential for mis-operation of a system; the potential for increasing initiating event frequency or impact on multiple mitigating systems; and the ability of operators to respond in a correct and timely manner to plant transients and accidents.
b. Findings No findings of significance were identified.
1R17 Permanent Plant Modifications (71111.17)
a. Inspection Scope The inspectors reviewed the installation of multiple modifications associated with the Unit 2 extended power uprate and installation of a digital feedwater level control system.
A list of the specific modification packages reviewed is included in the List of Documents Reviewed section of this report.
The inspectors verified that modification preparation, staging, and implementation did not impair the ability to complete plant emergency and abnormal operating procedure actions
if required, monitor key safety functions, or respond to a loss of key safety functions.
The inspectors reviewed the design adequacy of the modification by verifying the following:
- energy requirements were able to be supplied by supporting systems under accident and event conditions;
- replacement components were compatible with physical interfaces;
- replacement component properties met functional requirements under event and accident conditions;
- replacement components were environmentally and seismically qualified,
- sequence changes remained bounded by the accident analyses and loading on support systems was acceptable;
- structures, systems, and components response times were sufficient to serve accident and event functional requirements assumed by the design analyses;
- control signals were appropriate under accident and event conditions; and
- affected operations procedures were revised and training needs were evaluated in accordance with station administrative procedures.
The inspectors also verified that the post modification testing demonstrated system operability by verifying no unintended system interactions occurred, system performance characteristics met the design basis, and post-modification testing results met all acceptance criteria. The inspectors discussed the modifications with station operators, electrical maintenance, and engineering personnel.
b. Findings No findings of significance were identified.
1R19 Post Maintenance Testing (71111.19)
a. Inspection Scope The inspectors reviewed the post-maintenance test data for the following activities associated with Initiating Event and Mitigating Systems Cornerstone equipment:
System Date Inspected Engineering Change 334431, Standby Liquid Control Pump and February 27, 2002 Relief Valve Design Change Work Order 00397663, 2B Control Rod Drive Pump Does Not February 28, 2002 Rotate Properly Multiple Work Order Activities Associated with a 10-Year March 04, 2002 Overhaul of the High Pressure Coolant Injection System Refueling Outage Activities on the Reactor Core Isolation March 04, 2002 Cooling System TIC-320, Pressure Regulation System Extended Power Uprate March 04, 2002 Startup Test Procedure
b. Findings No findings of significance were identified.
1R20 Refueling and Outage (71111.20)
a. Inspection Scope The inspectors observed shutdown activities for the Unit 2 refueling outage which began on February 12, 2002. The inspectors monitored the licensees cooldown process and ensured that Technical Specifications were followed during the transition into Modes 3, 4, and 5. As part of the 21-day outage, the inspectors monitored outage configuration management on a daily basis by verifying that the licensee maintained appropriate defense in depth to address all shutdown safety functions and satisfy Technical Specification requirements. Proper operation of the decay heat removal system was verified during multiple control room tours and observations. Between March 4 and 14, 2002, the inspectors conducted multiple startup observations including startup testing, preparations for generator sychronization, and extended power uprate implementation testing.
b. Findings No finding of significance were identified.
1R22 Surveillance Testing (71111.22)
.1 Review of Standby Liquid Control System Outage Surveillance a. Inspection Scope On February 15, 2002, operations personnel performed surveillance test QCTS 0340-01, Standby Liquid Control System Outage Surveillance. The purpose of this test was to verify that the suction lines between the standby liquid control system storage tank and the pumps were not blocked and that the system was able to provide flow to the reactor pressure vessel. When the 2A standby liquid control system train was actuated from the control room, the 2A pump started, the 2A explosive valve fired as expected, and then the 2A pump tripped 1 to 3 seconds later. The inspectors reviewed the licensees actions following the unexpected pump trip and evaluated the licensees previous corrective actions following an identical pump trip in 1995.
b. Findings The inspectors identified one Green finding due to the licensees failure to take corrective actions to prevent recurrence following an identical pump trip in 1995. At Quad Cities the standby liquid control system control circuits were ungrounded as part of the original design. During actuations of the standby liquid control system explosive valves, electrical continuity of the explosive valve circuitry may be maintained due to fragments of the circuitry remaining intact following valve firing. Engineering personnel determined that if
the intact fragments contacted the standby liquid control system piping, a circuit path to ground was created. Under normal conditions the presence of a single ground created by the intact fragments would not be expected to affect system or control circuit operation. However, the licensee also discovered a previously unidentified independent ground at a different point in the control circuitry. The licensee determined that if operations personnel actuated the 2A standby liquid control system and continuity was not lost, the presence of two grounds created a condition where the voltage was not adequate to support continued system operation.
The inspectors discussed this issue with engineering personnel and learned that the 2A standby liquid control pump tripped during the performance of QCTS 0340-01 in 1995. Following the 1995 failure, the licensee performed troubleshooting and believed that the pump trip was caused by a failure of the pump motor overloads. As part of the corrective actions for the 1995 failure, the licensee replaced the pump motor overloads and implemented an additional corrective action to identify unintended grounds using a multimeter. Following the February 2002 pump failure, the licensee determined that troubleshooting performed in 1995 was inadequate in that it failed to identify the actual cause of the pump trip. The licensee also determined that the additional corrective actions were also inadequate since the use of a multimeter would not detect all unintended grounds.
Criterion XVI of 10 CFR Part 50, Appendix B, requires, in part, measures be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. The failure to adequately determine the cause of the 1995 2A standby liquid control system pump trip and take corrective actions to preclude repetition was considered a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion XVI (NCV 50-265/02-04-02). This issue was included in the licensees corrective action program as Condition Report 00095280.
The inspectors reviewed the risk significance of this issue and determined that the failure to determine the cause of the 1995 2A standby liquid control pump trip and take corrective actions to preclude repetition was more than minor because the issue could have a credible impact on safety and it affected the availability and function of a train in a mitigating system. The inspectors screened the issue using the Significance Determination Process and determined the risk significance of this issue to be very low (Green) because the 2B train of the standby liquid control system was unaffected by this issue and all remaining mitigating equipment was available to respond to an anticipated transient without scram event. As part of the corrective actions for this issue, the licensee replaced the components identified as possible sources of the undetected ground and modified the 2A standby liquid control circuitry such that the presence of another undetected ground would not impact pump or system operability.
.2 Review of other Surveillance Testing Activities a. Inspection Scope The inspectors observed surveillance testing activities and/or reviewed completed packages for the tests listed below related to systems in the Barrier Integrity and Mitigating Systems Cornerstones:
Unit Surveillance Procedure Observed Date Observed 1 Standby Liquid Control System Outage Surveillance February 14, 2002 1 Main Steam Isolation Valve Local Leak Rate Test February 26, 2002 1 Standby Liquid Control Pump Flow Rate Test February 27, 2002 1 Diesel Generator Cooing Water Pump Flow Rate Test February 28, 2002 1 Diesel Generator Fuel Oil Transfer Pump Flow Rate Test February 28, 2002 2 Division II Emergency Core Cooling System Simulated February 28, 2002 Automatic Actuation and Diesel Generator Auto-Start Surveillance 2 Emergency Diesel Generator Largest Load Reject February 28, 2002 Surveillance 2 4kV Bus 24-1 Undervoltage Functional Test February 28, 2002 2 4kV Bus 23-1 Undervoltage Functional Test February 28, 2002 The inspectors verified that Technical Specifications, Updated Final Safety Analysis Report, and licensees procedure requirements were met during each testing evolution.
Pump and valve performance results were compared against inservice testing requirements for those components subject to the program. The inspectors also verified that the testing demonstrated that the structure, system, or component was capable of performing its intended function.
b. Findings No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope The inspectors reviewed a temporary modification that installed a hose to allow a portion of the reactor water cleanup system flow to be diverted to the B feedwater header and the associated 10 CFR Part 50.59 screening. The inspectors compared the contents of
these documents against design basis information in the Updated Safety Analysis Report.
The inspectors reviewed drawings and verified that the hose installation points did not impact secondary containment operability. The inspectors discussed the temporary modification with operations and engineering personnel and reviewed Condition Report 00095756, Evaluation of Temporary Configuration Change not Properly Documented.
The inspectors also reviewed the temporary modification regarding temporary power for the Unit 2 902-50 (120V/240V instrument bus) during installation of design change package 9900708 and the associated 10 CFR 50.59 screening. The inspectors compared the contents of these documents against the system design basis information including the Updated Final Safety Analysis Report, Technical Specifications, and the Technical Requirements Manual.
b. Findings No findings of significance were identified.
2. RADIATION SAFETY Cornerstone: Occupational Radiation Safety 2OS1 Access Controls for Radiologically Significant Areas (71121.01)
.1 Plant Walkdowns, Radiological Boundary Verifications and Radiation Work Permit Reviews a. Inspection Scope The inspector conducted walkdowns of the radiologically protected area to verify the adequacy of radiation area boundaries and postings including high and locked high radiation areas in the Unit 1 and 2 reactor buildings including the Unit 2 drywell, and the turbine building. Confirmatory radiation measurements were taken to verify that these areas and selected radiation areas were properly posted and controlled in accordance with 10 CFR Part 20, licensee procedures, and Technical Specifications. The inspector walked down areas having the potential for airborne activity and verified the adequacy of the licensees continuous air monitoring systems and contamination control process.
Selected radiation work permits for radiologically significant work being conducted during Q2R16 were reviewed for protective clothing requirements and electronic dosimetry alarm setpoints for both dose rate and accumulated dose.
b. Findings No findings of significance were identified.
.2 Job-In-Progress Reviews a. Inspection Scope The inspector observed work occurring on the refueling floor including reactor disassembly, diving, and refueling operations. Work progress was observed in the drywell, low and high pressure heater bays and the outboard main steam isolation valve area. Radiation Work Permit requirements and the As-Low-As-Reasonably-Achievable (ALARA) briefing packages for selected jobs were reviewed. The inspector verified that dosimetry placement, alarm setpoints, job site radiological surveys, radiological exposure estimates, contamination controls, airborne monitoring for radioactive materials, and postings were adequate given the jobs radiological conditions.
b. Findings No findings of significance were identified.
.3 High Risk Significant, High Dose Rate, High Radiation Area, and Very High Radiation Area Controls a. Inspection Scope The inspector reviewed the licensees controls for elevated radiation dose rate areas.
During plant walkdowns, the inspector observed areas that met the definition of locked high radiation areas and very high radiation areas to evaluate if they were adequately secured. There were no Performance Indicator occurrences for this area.
b. Findings No findings of significance were identified.
.4 Radiation Worker Performance a. Inspection Scope The inspector evaluated radiation worker (radworker) performance by observing the use of low dose waiting areas and proper use of protective clothing, based on radiation work permit requirements. Radiological conditions were discussed with radworkers to determine worker awareness of significant radiological conditions and electronic dosimetry setpoints. Radiological problem condition reports were reviewed to determine if weaknesses in radworker performance had been identified.
b. Findings No findings of significance were identified.
.5 Radiation Protection Technician Performance a. Inspection Scope Radiation protection technician performance was evaluated with respect to radiological work requirements. The inspector observed control of radworkers, job coverage, control of contamination, and exit boundaries during job evolutions, and reviewed technician response to radiological incidents. Radiological problem condition reports were reviewed to determine if technician errors had been identified.
b. Findings No findings of significance were identified.
20S2 ALARA Planning and Controls (71121.02)
.1 Job Site Inspection and ALARA Control a. Inspection Scope The inspector reviewed jobs being performed in areas of elevated dose rates, examined exposure estimates and work sites, and evaluated selected radiation work permits along with the associated ALARA briefing packages to verify that worker radiological exposure was minimized. Protective clothing requirements, dosimeter use including radiotelemetry dosimetry, and electronic dosimeter alarm setpoints for both dose rate and accumulated dose were evaluated. The use of engineering controls was also reviewed to verify that worker exposures were maintained ALARA.
The inspector attended selected pre-job ALARA and work control briefings, and observed portions of work evolutions directly and by using the licensees remote closed circuit monitoring system in order to verify that adequate work controls were in place to maintain worker exposures ALARA. During job site walkdowns, radworkers and supervisors were observed to determine if low dose waiting areas were being used appropriately, and to evaluate the effectiveness of job supervision including equipment staging, use of shielding, availability of tools, and work crew size.
b. Findings No findings of significance were identified.
4. OTHER ACTIVITIES (OA)
4OA2 Performance Indicator Verification (71151)
Cornerstone: Barrier Integrity
.1 Reactor Coolant System Leakage Performance Indicator a. Inspection Scope The inspectors verified the Unit 1 and Unit 2 Reactor Coolant System Leakage Performance Indicator data reported by the licensee for January 2001 through December 2001. In particular, the inspectors reviewed Performance Indicator data sheets which formed the basis for the reported reactor coolant system leakage and compared that data to control room operating logs and leakage surveillance to determine if the reactor coolant system leakage was properly identified and reported. The inspectors also verified performance indicator results through independent calculations.
b. Findings No findings of significance were identified.
Cornerstone: Mitigating Systems
.2 Safety System Unavailability - Residual Heat Removal a. Inspection Scope The inspectors reviewed operator logs, performance indicator guidance procedures, and licensee safety system performance sheets to verify the licensees residual heat removal system unavailability performance indicator information for the second and fourth quarters of 2001 on Unit 1, and the first quarter 2001 on Unit 2.
b. Findings No findings of significance were identified.
4OA2 Problem Identification and Resolution (71152)
Maintenance Risk Assessments and Emergent Work Control a. Inspection Scope As part of the Maintenance Risk and Emergent Work Control inspection, the inspectors verified that the licensee has entered the problems identified during the inspection into their corrective action program. Additionally, the inspectors verified that the licensee is identifying issues at an appropriate threshold and entering them in the corrective action program, and verified that problems included in the licensee's corrective action program are properly addressed for resolution.
b. Findings As documented in Section 1R13 of this report, the inspectors conducted an inspection of the licensees Maintenance Risk assessment for week ending March 23, 2002. During the routine monitoring of the licensees scheduled daily work, the inspectors identified that licensee personnel failed to appropriately evaluate the availability of the Unit 1 high pressure coolant injection pump prior to the performance of Quad Cities Operating Surveillance (QCOS)-2300-28, U1 HPCI Turning Gear Logic Functional.
The inspectors raised the question of pump availability with the licensee, who indicated that the risk profile for the scheduled surveillance was already run and showed that the overall risk to the plant would remain at baseline Green condition indicating that the pump would remain available. The unavailability of high pressure coolant injection would change the risk to 1.43x baseline and result in an elevated Yellow risk condition based on safety function.
The inspectors had identified that the surveillance closed the high pressure coolant injection turbine steam supply valve and opened the breaker for the valve rendering the pump unavailable for mitigation purposes without operator action. The inspectors questioned the licensee on the compensatory plans that they had in place for the surveillance to ensure the availability of the high pressure coolant injection pump and they had none.
In response to the inspectors questions the licensee reevaluated the planned work and came to the conclusion that high pressure coolant injection system could not start and inject to meet the design function without operator assistance during the performance of the surveillance. The licensee decided to perform compensatory actions by stationing an operator to quickly close the breaker for the high pressure coolant injection turbine steam supply valve during the surveillance so that it would remain available. The licensee wrote Condition Report 100473 documenting the incorrect/incomplete risk assessment.
4OA3 Event Follow-up (71153)
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.
b. Findings (Closed) Licensee Event Report 50-254/02-001: Reactor Shutdown due to Failure of Reactor Recirculation Jet Pump. On January 9, 2002, the hold down beam on Quad Cities Unit 1 jet pump beam number 20 failed. Operations personnel entered Technical Specification 3.4.2.A due to differences in jet pump flow and initiated actions to shut down the plant. Approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> later, Unit 1 entered Mode 3 and began a 26-day forced outage to replace multiple jet pump beams. The Nuclear Regulatory Commission
conducted a special inspection of this event which was documented in Inspection Report 50-254/02-03. The licensee determined that the jet pump hold down beam failure was caused by intergranular stress corrosion cracking in the transition portion of the beam.
Corrective actions for this issue included replacing all of the BWR/3 jet pump hold down beams with improved BWR/4 hold down beams. The licensee also performed an operability evaluation to support the continued operation of Quad Cities Unit 2 with BWR/3 jet pump beams until the start of the Unit 2 refueling outage. The inspectors reviewed the licensees operability determination and the corrective actions for this event and had no concerns. No violations of NRC requirements were identified since the licensee had followed all previous industry guidance regarding jet pump hold down beam failures and inspections.
(Closed) Licensee Event Report 50-265/01-002: Potential Common Cause Inoperability of Emergency Diesel Generator Fuel Oil Transfer System. One Green finding was identified for the inadequate design of the Unit 2 emergency diesel generator fuel oil transfer system. On May 1, 2001, and May 3, 2001, a solenoid valve in the Unit 2 emergency diesel generator fuel oil transfer system failed to open approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the start of the emergency diesel generator 24-hour endurance test. The licensee determined that the solenoid valve failure was due to thermal pressurization of an isolated section of fuel oil transfer system discharge piping. Specifically, the original design of the fuel oil transfer system was inadequate in that the thermal effects in the piping volume between the discharge check valve and the solenoid valve were not accounted for. The failure to factor thermal effects into the original plant design resulted in a condition where the pressure increase due to the thermal effects exceeded the operating capabilities of the solenoid operator.
The inspectors determined that a common cause inoperability of the three emergency diesel generator fuel oil transfer systems did not occur due to differences in the operating capabilities of the solenoid operators. However, the inadequate design of the Unit 2 fuel oil transfer system solenoid valve was more than minor because if left uncorrected, the issue may become more of a significant safety concern if the emergency diesel generator was required to respond to an event under the same thermal conditions or the day tank low level alarm failed to function. In addition, the issue could credibly affect the operability, availability, reliability, or function of a system or train in a mitigating system.
The inspectors screened this issue using the Significance Determination Process and determined the risk significance of this issue to be very low (Green) because the Unit 2 station blackout diesel generator was not impacted by this design issue, actions to manually fill the fuel oil day tank were proceduralized such that recovery of the emergency diesel generator should be successful, and alternative mitigating equipment was available to respond to a potential loss of offsite power.
Criterion III to 10 CFR Part 50, Appendix B requires, in part, measures shall be established to assure that applicable regulatory requirements and the design basis for those structures, systems, and components to which this Appendix applies are correctly translated into specifications, drawings, procedures, and instructions. The design control measures shall provide for verifying or checking the adequacy of design. Design control measures shall be applied to items such as stress, thermal, hydraulic, and accident analyses; compatibility of materials; accessibility for inservice inspection, maintenance, and repair; and delineation of acceptance criteria for inspections and tests. The failure to
establish measures to assure that items such as thermal effects and the compatibility of materials were correctly translated into specifications for the Unit 2 emergency diesel generator fuel oil transfer system was considered a Non-Cited Violation (NCV 50-265/02-04-03) of 10 CFR Part 50, Appendix B, Criterion III. This issue was entered into the licensees corrective action program as Condition Reports Q2001-01312, Q2001-01338, and Q2001-02518.
4OA6 Meetings
.1 Deputy Executive Director for Operations visits Quad Cities On February 26, 2002, William F. Kane, Deputy Executive Director for Operations and James Dyer, Region III Regional Administrator visited the Quad Cities Station. In addition to a plant tour, Messrs. Kane and Dyer participated in discussions on recent security enhancements, plant equipment failures, implementation of extended power uprate activities, and station opportunities and challenges.
.2 Inspection Period Exit Meeting The inspectors presented the inspection results to Mr. Tulon and other members of licensee management at the conclusion of the inspection on April 2, 2002. The licensee acknowledged the findings presented. No proprietary information was identified.
.3 Interim Exit Meetings Senior Official at Exit: Mr. Timothy Tulon, Site Vice President Date: February 15, 2002 Proprietary Information: No Subject: Radiological Access Control Program, and the ALARA Planning and Controls Program Senior Official at Exit: Mr. Timothy Tulon, Site Vice President Date: February 28, 2002 Proprietary Information: No Subject: Biennial Inservice Inspection
PARTIAL LIST OF PERSONS CONTACTED Licensee T. Tulon, Site Vice President C. Swenson, Plant Manager D. Barker, Radiation Protection Manager W. Beck, Regulatory Assurance Manager G. Boerschig, Engineering Manager R. Gideon, Work Control Manager A. Javorik, Maintenance Manager K. Leech, Security Manager K. Moser, Chemistry/Environ/Radwaste Manager K. Ohr, Radiation Protection Supervisor M. Perito, Operations Manager M. Snow, Nuclear Oversight Manager NRC M. Ring, Chief, Reactor Projects Branch 1 ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-265/02-04-01 FIN Catastrophic Failure of 2B Control Rod Drive Pump (Section 1R14)
50-265/02-04-02 NCV Failure to Adequately Determine Cause of SBLC Pump Trip and Take Corrective Action (Section 1R22)
50-265/02-04-03 NCV Failure to Establish Measures to Assure that Items were Correctly Translated into Specifications (Section 4A03)
Closed 50-265/02-04-01 FIN Catastrophic Failure of 2B Control Rod Drive Pump (Section 1R14)
50-265/02-04-02 NCV Failure to Adequately Determine Cause of SBLC Pump Trip and Take Corrective Action (Section 1R22)
50-265/02-04-03 NCV Failure to Establish Measures to Assure that Items were Correctly Translated into Specifications (Section 4A03)
50-254/02-001 LER Reactor Shutdown due to Failure of Reactor Recirculation Jet Pump (Section 4A03)
50-265/01-002 LER Potential Common Cause Inoperability of EDG Fuel Oil Transfer System (Section 4A03)
LIST OF ACRONYMS AND INITIALISMS USED ALARA As-Low-As-Is-Reasonably-Achievable ASME American Society of Mechanical Engineers CFR Code of Federal Regulations CR Condition Report HPCI High Pressure Coolant Injection LER Licensee Event Report LS-AA Licensing Services All Sites Mwe Megawatts Electric Radworker Radiation Worker QCGP Quad Cities General Procedures QCOP Quad Cities Operating Procedures QCOS Quad Cities Operating Surveillance SDP Significance Determination Process SSCs Structures, Systems, or Components Vdc Volt direct current VIO Violation WO Work Order
LIST OF DOCUMENTS REVIEWED 1R04 Equipment Alignment Number Subject/Title Date/Revision QCOP 2900-01 Safe Shutdown Makeup Pump System Revision 16 Preparation For Standby Operation QCOP 7500-01 Standby Gas Treatment System Standby Revision 12 Operation and Startup QCOP 1400-01 Core Spray System Preparation for Standby Revision 13 Operation QOP 6900-01 250 VDC Electrical System QOP 6900-02 125 VDC Electrical System QOP 6900-03 48/24 VDC Electrical System Drawing 4E-1317 250 VDC Motor Control Centers, Unit 1 Drawing 4E-1318B 125 VDC Distribution Centers 1R05 Fire Protection Number Subject/Title Date/Revision Commonwealth Edison Company Quad Cities Revision 20 Nuclear Power Station 1 & 2 Pre-Fire Plans Number RB-7 Pre-Fire Plan 1.1.1.2 ComEd Quad Cities 1 and 2 Fire Protection Revision 12 Reports Volume 1, Updated Fire Hazard Analysis Condition Report Sprinkler Nozzles Found Blocked in Cable January 8, 2002 00089496 Spreading Room Quad Cities Fire Individual Plant Examination Revision 0 for External Events Update, Appendix I, Fire Compartment 3.0, Unit 1/2 Cable Spreading Room Fire Drill Scenario 1ST Quarter
1R12 Maintenance Rule Implementation Number Subject/Title Date/Revision Maintenance Rule Package for TBCCW Condition Report 1A TBCCW Pump Mechanical Seal Failure Q2001-01410 Work Order 1A TBCCW Pump Oil Leak 99224772 Condition Report 1B Core Spray Room Cooler Temperature Q2001-03119 Switch was Found Out-of-Tolerance Calculation QC-716- Maximum Room Temperature for Core Spray Revision 3 M-001 and RHR Corner Pump Rooms following a January 7, 1993 Postulated Event Outside These Rooms and Verification Adequacy of Room Coolers in These Rooms Calculation NED-I- Setpoint Calculation for RHR and Core Spray October 15, 1993 EIC-0227 Pump Room Temperature Switches Quad Cities Design Emergency Core Cooling System Room June 1, 1999 Calculation-5700-M- Cooler Performance Calculation Under Design 0806 Basis and Degraded Conditions Condition Report NOS Identified MRFFs not Counted in MR 00089557 Program Condition Contactor Stuck Shut for the 2A Residual Heat ReportQ2001-03053 Removal Pump Room Cooler Normal Supply Maintenance Rule Expert Panel Review Various Dates Evaluation History of Condition Report Q2001-03053 Expert Panel Scoping Determination for November 16, Function Z5711 2001 Maintenance Rule Performance Criteria for November 26, Function Z5711 2001 Condition 2-2301-04 Failed to Stroke Closed During ReportQ2001-02784 QCOS 2300-06 Expert Panel Scoping Determination for January 29, 2002 Function Z0010-01 Maintenance Rule Performance Criteria for January 29, 2002 Function Z0010-01
Maintenance Rule Expert Panel Review Various Dates Evaluation History of Condition Report Q2001-02784 Maintenance Rule Expert Panel Minutes October 11, 2001 Maintenance Rule Expert Panel Minutes November 16, 2000 Maintenance Rule Expert Panel Minutes April 06, 2000 Maintenance Rule Expert Panel Minutes February 24, 2000 4E-2529 Quad Citieis Electrical Schematic Drawing Quad Cities Updated Final Safety Analysis Revision 6 Report, Section 7.3.2.2 1R13 Maintenance Risk Assessment and Emergent Work Number Subject/Title Date/Revision OU-AA-103 Shutdown Safety Management Program Revision 1 Work Week Safety Profile Week of March 18, 2002 OU-QC-104, Daily Risk Factor Chart Revision 1 Attachment 1 OU-QC-104 Shutdown Safety Management Program Quad Revision 1 Cities Annex Operations Logs Daily during outage WC-AA-103 On-Line Maintenance Revision 4 Work Week Safety Profile Week of March 30, 2002 QCOS 2300-28 HPCI Turning Gear Logic Functional Test Revision 7 Unit 1 and 2 Daily Risk Assessment March 19, 2002 Unit 1 and 2 ORAM-SENTINEL Input and March 19, 2002 Results
1R14 Non-Routine Evolutions Number Subject/Title Date/Revision Engineering 1A Moisture Separator Drain Tank Normal Revision 0 Operational Problem Drain to 1D3 Heater Response 02-01-3500-001 QCOA 3500-01 Feedwater Temperature Reduction With Main Revision 16 Turbine Online QCOP 3500-02 Moisture Separator Normal Drainage Revision 5 QCAN 901(2)-6 C-1 Feedwater Heater 1(2)D1 High Level Revision 0 Condition Report 2B Control Rod Drive Pump Catastrophic January 24, 2002 00092250 Failure Work Order 2B Control Rod Drive Pump Does Not Rotate January 12, 2002 00397663 Root Cause Report Catastrophic Failure of 2B Control Rod Drive March 8, 2002 for Condition Report Pump due to Improperly Set Line Bearing Oiler 00092250 MA-AA-MM-4-00400 Constant Level Oiler and Sightglass Revision 0 Maintenance Condition Report U2 EHC Leak Causes Unplanned Load March 29, 2002 00101500 Reduction Work Order U2 #1TCV EHC Leak March 29, 2002 425265 QCGP-2-1 Normal Reactor Shutdown Revision 33 QCGP-3-1 Reactor Power Operations Revision 25 QCOP-3200-05 Reactor Feed Pump Shutdown Revision 13 QCOP-3300-03 Condensate System Shutdown Revision 07 1R15 Operability Evaluations Number Subject/Title Date/Revision Action Tracking Item Operability Evaluation for RHRSW Vault Room 93444-08 Cooler Piping Leak
1R17 Permanent Plant Modifications Engineering Change Subject/Title Date/Revision Number 24284 APRM and Turbine Trip Bypass Setpoint Multiple Revisions Changes 24404 Recirculation Pump Runback Loss of Multiple Revisions Feedwater Pump 24406 LPCI Swing Bus Time Delay Setpoint Change Multiple Revisions 24166 Condensate Pump D Control Circuit Trip Logic Multiple Revisions 24408 Condenser Low Vacuum Setpoint Change Multiple Revisions 24461 Digital Feedwater Multiple Revisions 334431 Standby Liquid Control Pump and Relief Valve Multiple Revisions Design Change TIC-343 U2 Standby Liquid Control Pump Modification Revision 0 Test QCOS 6700-02 MCC 28/29-5 Auto Transfer Logic Operability Revision 5 Test Calculation Determination of Pressure Drop Through Revision 000A QDC-1100-M-0379 Discharge Piping for Two Pump Injection of Standby Liquid Control System 1R19 Post Maintenance Testing Number Subject/Title Date/Revision TIC-343 U2 Standby Liquid Control Pump Modification Revision 0 Test QCTS 0340-01 Standby Liquid Control System Outage Revision 8 Surveillance Work Order 2B Control Rod Drive Pump Does Not Rotate Revision 1 00397663 Properly QCOS 2300-07 High Pressure Coolant Injection System Revision 18 Turbine Overspeed Test QCOS 2300-01 Periodic High Pressure Coolant Injection Pump Revision 38 Operability Test QCOS 1300-01 Periodic Reactor Core Isolation Cooling Pump Revision 28 Operability Test
TIC-320 Pressure Regulation System EPU Startup Test Revision 0 Procedure Condition Report 2B Control Rod Drive Pump Catastrophic January 24, 2002 00092250 Failure 1R20 Refueling and Outage Number Subject/Title Date/Revision OU-AA-103 Shutdown Safety Management Program Revision 1 Work Week Safety Profile Week of March 18, 2002 OU-QC-104, Daily Risk Factor Chart Revision 1 Attachment 1 OU-QC-104 Shutdown Safety Management Program Quad Revision 1 Cities Annex Operations Logs Daily during outage 1R22 Surveillance Testing Number Subject/Title Date/Revision QCOS 1100-07 SBLC Pump B Flow Rate Test Revision 20 QCOS 6600-06 Unit 1 Diesel Generator Cooing Water Pump Revision 20 Flow Rate Test QCOS 6600-05 Unit 1 Diesel Generator Fuel Oil Transfer Revision 17 Pump Flow Rate Test Work Order Perform Calibration of 1-3941-26 per QIP 99185533 0100-19 Work Order Calibrate FI 1-3941-28 per QIP 0100-19 99240417 Work Order Perform Calibration of 1-3941-49 per QIP 99246071 0100-11 Work Order Perform Calibration of 1-3941-45 per QIP 99184401 0100-19 Work Order Perform Calibration of 1-3941-24 per QIP 99184402 0100-19
Technical Specification 5.5.6, Inservice Testing Program of ASME Class 1, 2, and 3 Pumps and Valves UFSAR Section 3.9.6, Inservice Testing of Pumps and Valves Action Request Boric Acid Crystals Inside SBLC Pump B 123801 Stuffing Box Action Request U1DG FOTP Discharge Pressure Gage Reads 139286 1-inch Vacuum, Should Be 0 inch Critical Control Room Diagram of Standby Liquid Control Piping Revision AU Drawing M-40 QCTS 060-05 Main Steam Isolation Valve Local Leak Rate Revision 11 Test QCOS 6600-48 Unit 2 Division II Emergency Core Cooling Revision 3 System Simulated Automatic Actuation and Diesel Generator Auto-Start Surveillance QCOS 6600-39 Unit 2 Emergency Diesel Generator Largest Revision 7 Load Reject Surveillance QOS 6500-02 4KV Bus 24-1 Undervoltage Functional Test Revision 35 QOS 6500-04 4KV Bus 23-1 Undervoltage Functional Test Revision 19 QCTS 0340-01 Standby Liquid Control System Outage Revision 8 Surveillance Condition Report 2A SBLC Pump Tripped While Performing February 15, 2002 00095280 QCTS 0340-01 Apparent Cause Report for Condition Report March 1, 2002 00095280 Condition Report During QCTS 340-1, Standby Liquid Control May 14, 1995 Q1995-01511 Outage Surveillance, the Squib Valve Failed 1R23 Temporary Modifications Number Subject/Title Date/Revision Condition Report Evaluation of Temporary Configuration Change February 19, 2002 00095756 not Properly Documented TIC-334 New Temporary Procedure to Allow RWCU to February 2, 2002 be Injected into the 1B Feedwater Header
Critical Control Room Diagram of Reactor Water Clean-up Piping Revision T Drawing M-47, Sht. 1 Critical Control Room Diagram of Reactor Feed Piping Revision BF Drawing M-15, Sht. 1 Temporary Installation of Temporary Power to Unit 2 902- November 16, Modification 332020 50 2001 2OS1 Access Control 10000309 (U2 RX) Steam Dryer: Mod to Reduce Revision 0 Carryover (Divers) (Q2R16)
10000227 (U2 DW) PORV/SRV/Target Rock Valves: Revision 1 Remove/Replace 10000264 (U2 DW) EPU Uprate Mod: Support Steel Revision 0 Modifications (Q2R16)
10000314 U2 Torus Desludge: Support Activities Revision 0 (Q2R16)
10000250 (U2 DW) MSIP Weld Treatment Q2R16 Revision 0 RP-AA-460 Controls for High and Very High Radiation Revision 2 Areas 94917 Reactor Vessel Insulation package Buildup of February 12, 2002 Pressure 91646 RP Observed Poor Radworker Practices at the January 23, 2002 Drywell and 690 93929 Personnel Passing EDs through X-Ray February 5, 2002 Machine in Main Access 84480 Operator Discovered Higher than Expected November 29, Dose Rates 2001 82285 RPT Identified Worker Outside RPA With New November 8, 2001 Yellow Gloves 82642 NO Identified Problems at the A RHR SOP November 12, Area on the 595 Elevation 2001 82997 RWP Self Assessment Results November 14, 2001 85565 Contractor Personnel Chewing Gum in RPA December 7, 2001 87133 Missed Dose Savings Opportunity December 17, 2001
88902 Unplanned Spread of Contamination-2B December 27, Cleanup Pump Room 2001 88945 Unplanned Spread of Contamination 1B December 27, RWCU Pump Seal Failed 2001 90486 Contamination Monitor Alarms on Workers January 13, 2002 Shoe Bottoms from 690 91047 Unplanned Spread of Contamination U-1 North January 17, 2002 CRD Bank 91578 Unexpected Dose Rates in U-2 Recombiner January 17, 2002 Room 93629 Scaffolds Added to Pre-Outage Scope Late February 2, 2002 92259 Unplanned Spread of Contamination January 24, 2002 92286 Venture Person Entered DW 1 Under Wrong January 25, 2002 RWP 94253 GE Personnel Empty Contaminated Tools On February 7, 2002 A Clean Floor 94259 Unplanned Spread of Contamination February 7, 2002 94520 Inappropriate Radworker Practice at Trackway February 8, 2002
- 1 2OS2 ALARA Planning and Controls 162 ALARA RP Brief Summary: Modifications on Reactor Steam Dryer 163 ALARA RP Brief Summary: U2 PORV/SRV/Target Rock Valves:
Remove/Replace 160 ALARA RP Brief Summary: (U2 DW) EPU Uprate Mod: Support Steel Mods 56 ALARA RP Brief Summary: Torus Desludge Support Activities 10000309 ALARA Plan U2 EPU Mod: Steam Dryer February 12, 2002 Modification Diving Activities 10000227 ALARA Plan PORV/SRV/Target Rock Valves: February 13, 2002 Remove/Replace 10000264 ALARA Plan (U2 DW) EPU Uprate Mod: February 8, 2002 Support Steel Modification
10000314 ALARA Plan U2 Torus Desludge: Support February 13, 2002 Activities 10000250 ALARA Plan MSIP Weld Treatment February 13, 2002 10000268 ALARA Plan (U2 DW) Auto UT Exams (6) February 11, 2002 Recirc Welds Q2R16 RP-AA-400 ALARA Program Revision 1 RP-AA-401 Operational ALARA Planning and Controls Revision 1 Organization Chart for Q2R16 4OA2 Performance Indicator Verification LS-AA-2100 Monthly Performance Indicator (PI) Data Elements for Reactor Coolant System (RCS)
Leakage QCOS 1600-07 Drywell Equipment Drain sump Leakage Data Revision 18 Sheet Condition Report Work Week Safety Profile Did Not Reflect July 11, 2001 00056436 Yellow Risk for 1A Core Spray Condition Report Near Miss on Shutdown Safety February 23, 2002 00095705 Condition Report OU-QC-104 Required Changes February 26, 2002 00096466 Condition Report NO Identified: Several Improvements to December 03, 00084166 Q2R16 SD Risk Matrix 2001 Condition Report Q2001-01634 Interpretation of On-Line Risk June 06, 2001 00053586 Inputs Condition Report Incorrect Availability Call for QCOS 2300-28 on March 22, 2002 100473 U1 HPCI OU-AA-103 Shutdown Safety Management Program Revision 1 OU-QC-104 Daily Risk Factor Chart Revision 1 WC-AA-101 On-Line Work Control Process Revision 6 LS-AA-125 Corrective Action Program (CAP) Procedure Revision 2 RS-AA-122-104 Performance Indicators-Safety System January 2001 Unavailability (HPCI,RHR,RCIC,EDG)
RS-AA-122-104 Performance Indicators-Safety System February 2001 Unavailability (HPCI,RHR,RCIC,EDG)
RS-AA-122-104 Performance Indicators-Safety System March 2001 Unavailability (HPCI,RHR,RCIC,EDG)
RS-AA-122-104 Performance Indicators-Safety System April 2001 Unavailability (HPCI,RHR,RCIC,EDG)
LS-AA-2070 Monthly Performance Indicator Data Elements May 2001 for Safety System Unavailability-Residual Heat Removal Systems LS-AA-2070 Monthly Performance Indicator Data Elements June 2001 for Safety System Unavailability-Residual Heat Removal Systems LS-AA-2070 Monthly Performance Indicator Data Elements July 2001 for Safety System Unavailability-Residual Heat Removal Systems LS-AA-2070 Monthly Performance Indicator Data Elements August 2001 for Safety System Unavailability-Residual Heat Removal Systems LS-AA-2070 Monthly Performance Indicator Data Elements September 2001 for Safety System Unavailability-Residual Heat Removal Systems LS-AA-2070 Monthly Performance Indicator Data Elements October 2001 for Safety System Unavailability-Residual Heat Removal Systems LS-AA-2070 Monthly Performance Indicator Data Elements November 2001 for Safety System Unavailability-Residual Heat Removal Systems LS-AA-2070 Monthly Performance Indicator Data Elements December 2001 for Safety System Unavailability-Residual Heat Removal Systems LS-AA-2070 Monthly Performance Indicator Data Elements January 2002 for Safety System Unavailability-Residual Heat Removal Systems Unit 1 Operators Logs From April 1, 2001 to June 30, 2001 Unit 1 Operators Logs From October 1, 2001 to December 31, 2001 Unit 2 Operators Logs From January 1, 2001 to March 31, 2001
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