IR 05000255/2002009
| ML030280316 | |
| Person / Time | |
|---|---|
| Site: | Palisades  |
| Issue date: | 01/24/2003 |
| From: | Collins L NRC/RGN-III/DRP/RPB6 |
| To: | Cooper D Nuclear Management Co |
| References | |
| IR-02-009 | |
| Download: ML030280316 (58) | |
Text
ary 24, 2003
SUBJECT:
PALISADES NUCLEAR GENERATING PLANT NRC INSPECTION REPORT 50-255/02-09
Dear Mr. Cooper:
On December 28, 2002, the NRC completed an inspection at your Palisades Nuclear Generating Plant. The enclosed report documents the inspection findings which were discussed on January 7, 2003, with yourself 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, we identified three issues of very low safety significance (Green) that were determined to involve violations of NRC requirements. However, because of the very low safety significance and because the issues were 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 NRC s Enforcement Policy.
If you deny these Non-Cited Violations, you should provide a response with a basis for your denial, within 30 days of the date of this inspection report, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 801 Warrenville Road, Lisle, IL 60532-4351; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Palisades facility.
Since the terrorist attacks on September 11, 2001, the NRC has issued two Orders (dated February 25, 2002, and January 7, 2003) and several threat advisories to licensees of commercial power reactors to strengthen licensee capabilities, improve security force readiness, and enhance access authorization. The NRC also issued Temporary Instruction 2515/148 on August 28, 2002, that provided guidance to inspectors to audit and inspect licensee implementation of the interim compensatory measures (ICMs) required by the February 25th Order. Phase 1 of TI 2515/148 was completed at all commercial nuclear power plants during calendar year (CY) 02, and the remaining inspections are scheduled for completion in CY 03. Additionally, table-top security drills were conducted at several licensees to evaluate the impact of expanded adversary characteristics and the ICMs on licensee protection and mitigative strategies. Information gained and discrepancies identified during the audits and drills were reviewed and dispositioned by the Office of Nuclear Security and Incident Response. For CY 03, the NRC will continue to monitor overall safeguards and security controls, conduct inspections, and resume force-on-force exercises at selected power plants.
Should threat conditions change, the NRC may issue additional Orders, advisories, and temporary instructions to ensure adequate safety is being maintained at all commercial power reactors.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Laura Collins, Acting Chief Branch 6 Division of Reactor Projects Docket No. 50-255 License No. DPR-20
Enclosure:
Inspection Report 50-255/02-09
REGION III==
Docket No: 50-255 License No: DPR-20 Report No: 50-255/02-09(DRP)
Licensee: Nuclear Management Company, LLC Facility: Palisades Nuclear Generating Plant Location: 27780 Blue Star Memorial Highway Covert, MI 49043-9530 Dates: September 29 through December 28, 2002 Inspectors: J. Lennartz, Senior Resident Inspector R. Krsek, Resident Inspector R. Winter, Reactor Engineer C. Phillips, Senior Operations Engineer G. Larkin, Resident Inspector D. Nelson, Radiation Protection Inspector C. Osterholtz, Senior Resident Inspector T. Madeda, Physical Security Inspector S. Burgess, Senior Reactor Analyst Approved by: Laura Collins, Acting Chief Branch 6 Division of Reactor Projects
SUMMARY OF FINDINGS
IR 05000255/02-09, Nuclear Management Company, LLC, on 09/29/2002 - 12/28/2002,
Palisades Nuclear Generating Plant. Identification and Resolution of Problems.
This report covers a 3-month period of baseline resident inspections, an announced baseline inspection in radiation protection and an announced pre-inspection audit in physical protection.
The inspections were conducted by resident inspectors, regional inspectors and a radiation specialist inspector. The pre-inspection audit was conducted by a regional based physical security inspector. Three Green findings with associated Non-Cited Violations (NCVs) were identified during the inspection. 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 may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG 1649, Reactor Oversight Process, Revision 3, dated July 2000.
A. Inspector Identified Findings
Cornerstone: Initiating Events
- Green.
The inspectors determined that a self-revealed Green finding was associated with a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for the failure to rigorously evaluate industry operating experience information which resulted in inadequate preventive maintenance activities being developed for the 345 Kilo-Volt (KV) transmission lines that connect the plant and the switchyard.
Consequently, on December 1, 2002, a connector holding a static wire on the 345 KV transmission line towers between the plant and the switchyard failed. As a result, the static line contacted one phase of the 345 KV lines as well as all three phases of the 345 KV Rear Bus in the switchyard which caused an automatic plant trip on loss of generator load and a loss of startup power.
This self-revealed finding was determined to be of very low safety significance by the significance determination process because: (1) the finding did not contribute to the likelihood of a Primary or Secondary system Loss of Coolant Accident initiator; (2) the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available; and (3) the finding did not increase the likelihood of a fire or internal/external flood. (Section 4OA2.2)
Cornerstone: Mitigating Systems
- Green.
The inspectors determined that a self-revealed Green finding was associated with a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for the failure to adequately evaluate the root cause in 1992 of a leak that occurred on the instrument line for Safety Injection Tank T-82D. Consequently, past corrective actions were not adequate to prevent the leak from recurring on November 11, 2002. As a result,
T-82D was rendered inoperable and unavailable to perform the intended safety function of injecting borated water to the reactor during a large break loss of coolant accident. In addition, a NOED had to be issued to extend Technical Specification Limiting Condition
3.5.1, Safety Injection Tanks, allowed outage time by 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> so that repairs could be completed to restore T-82D to an operable status without having to shut down the plant.
This self-revealed finding was determined to be of very low safety significance by the significance determination process because: (1) the safety injection tanks were only credited for large break loss of coolant accidents; and (2) the exposure time for the inoperable safety injection tank was less than 3 days. (Section 4OA5.1)
Cornerstone: Barrier Integrity
- Green.
The inspectors determined that a self-revealed Green finding was associated with a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for the failure to promptly identify and correct problems regarding the operation of Mechanical Equipment Room Door-16, which resulted in the door failing in the open position of October 10, 2002.
This self-revealed finding was determined to be of very low safety significance by the significance determination process because the finding represented a degradation of only the radiological barrier function for the control room. (Section 4OA2.1)
B. Licensee Identified Findings None.
REPORT DETAILS
A list of documents reviewed within each inspection area is included at the end of the report.
Summary of Plant Status
The plant was at full power for the majority of the inspection period with the following two exceptions:
C On November 11, 2002, operations personnel identified a non-isolable leak from a 3/4 inch instrument tap for Level Transmitter LT-0374 off the 12 inch Safety Injection Tank 82D main discharge piping. Consequently, Tank 82D was declared inoperable and plant power was reduced to approximately 60 percent on November 12, 2002, to conduct repairs to the instrument line. Repairs were successfully completed and plant power was subsequently escalated to full power on November 13, 2002. (This issue is discussed further in Section 4OA5.1 of this report.)
C On December 1, 2002, an automatic reactor trip occurred on main generator loss of load. All safety systems operated as designed to maintain the plant in a stable condition following the trip. The main generator tripped because a connector that held a static wire to the 345 KV transmission line towers failed and the static wire contacted the 345 KV lines. As a result, the main generator output breaker tripped on loss of load and the reactor protection system tripped the reactor. After the plant trip, station loads automatically transferred to startup power momentarily.
However, startup power was lost approximately 2 seconds later when the static wire that was contacting the 345 KV lines overheated, separated at one section and fell across all three phases of the 345 KV Rear Bus in the switchyard causing a fault. Consequently, the switchyard breakers opened to clear the fault which resulted in a loss of Rear Bus and a resultant loss of startup power.
As a result, primary coolant pumps, circulating water pumps, and condensate pumps lost power. Consequently, the primary system was on natural circulation cooling and secondary heat removal was maintained with the auxiliary feedwater system and atmospheric dump valves. The plant remained in this condition until the 345 KV Rear Bus and startup power were recovered on December 3, 2002, after which primary coolant pumps were started to establish forced circulation in the primary system.
After the secondary systems were recovered, plant startup activities commenced on December 4, 2002. The main generator was synchronized to the grid on December 5th, and the plant was at full power on December 7, 2002. (This issue is discussed further in Sections 4OA2.2 and 4OA3.1 of this report.)
REACTOR SAFETY
Cornerstones: Initiating Event, Mitigating Systems, Barrier Integrity, Emergency Preparedness
1R01 Adverse Weather Protection
.1 Thunderstorm Warning With Forecasted High Wind Gusts
a. Inspection Scope
The inspectors reviewed the actions taken by operations personnel on October 4, 2002, after the site received a severe thunderstorm warning with possible wind gusts of 50 to 60 miles per hour. The inspectors conducted plant walkdowns to verify that actions as described in Off-Normal Procedure - 12, Acts of Nature, were being accomplished to the extent possible for the pending high wind conditions. The inspectors also verified that the Operators Risk Report, was updated to reflect the impact on plant risk for the pending severe thunderstorm and high wind condition, and verified that plant equipment was controlled to minimize plant risk to the extent possible.
b. Findings
No findings of significance were identified.
.2 Cold Weather Preparations
a. Inspection Scope
The inspectors reviewed plant procedures to protect risk significant systems from the onset of cold weather. The inspectors reviewed the Cold Weather Checklists performed on November 6, 18, and 19, 2002. The following systems were emphasized:
- Service Water Additionally, on December 6, 2002, the inspectors toured portions of the plant with an operations representative to verify that the selected systems were appropriately protected.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
.1 Quarterly Equipment Alignment Walkdowns
a. Inspection Scope
The inspectors performed two partial walkdowns of the Switchyard R Bus and Auxiliary Feedwater Pump P-8C. The inspectors performed the walkdowns to verify proper system lineup while redundant plant equipment was out of service. For the systems walked down, the inspectors verified that power was available, that accessible equipment and components were appropriately aligned, and that no discrepancies existed which would impact the systems function. Portions of the system alignment inspection included discussions and system walkdowns with operations and engineering personnel.
The inspectors also reviewed condition reports related to equipment alignment issues to verify that the problems were appropriately characterized.
b. Findings
No findings of significance were identified.
1R05 Fire Protection
.1 Fire Area Walkdowns
a. Inspection Scope
The inspectors toured the following six areas in which a fire could affect safety-related equipment:
- West Engineered Safeguards Room (Fire Area 28);
- Battery Rooms (Fire Area 11 & 12);
- East Mechanical Equipment Room (Fire Area 30);
- West Mechanical Equipment Room (Fire Area 31);
- Battery Room #1 (Fire Area 12); and
- Electrical Equipment Room (Fire Area 21)
The inspectors assessed the material condition of the passive fire protection features and verified that transient combustibles and ignition sources were appropriately controlled. Also, the inspectors reviewed documentation for randomly selected completed surveillances to verify the availability of the sprinkler fire suppression system, smoke detection system, and manual fire fighting equipment for these areas.
The inspectors also verified that the fire protection equipment that was installed and available in the fire areas corresponded with the equipment which was referenced in the applicable portions of the Final Safety Analysis Report, Section 9.6, Fire Protection.
Finally, the inspectors verified that compensatory actions were being implemented, as required, for designated Fire Areas where compensatory actions were needed.
In addition, the inspectors reviewed selected condition reports to verify that identified problems associated with fire protection were entered into the corrective action program with the appropriate significance characterization.
b. Findings
No findings of significance were identified.
.2 Fire Drill
a. Inspection Scope
The inspectors observed an unannounced fire drill on October 23, 2002. The drill included participation by two off-site fire departments which assisted the on-site fire brigade in fighting the simulated fire located in a pipe-way overhead structure between the feedwater purity building and the turbine building. The inspectors evaluated the fire brigades readiness to fight fires which included the following attributes:
C required number of fire brigade members as specified in Fire Protection Implementing Procedure -3, Plant Fire Brigade, reported to the scene in a timely manner; C fire brigade members ability to properly use protective clothing and self-contained breathing apparatus; C appropriate amount and type of fire fighting equipment was brought to the fire scene, fire hoses were laid out without flow restrictions and enough fire hose was available to reach the fire hazard; C fire brigade leaders ability to provide clear, thorough and effective directions to both the on-site fire brigade members and to personnel from the off-site departments; C off-site fire department equipments compatibility with on-site fire fighting equipment; C ability to communicate between fire brigade members and the control room operators in an effective manner; C fire brigade leaders ability to use fire fighting pre-plan strategies in an effective manner.
In addition, the inspectors verified that the pre-planned drill scenario was followed and that the drill objectives were met. The inspectors observed the post-drill critique to assess the licensee evaluators ability to identify problems regarding the fire brigades ability and readiness to fight fires. The inspectors also reviewed condition reports to verify that problems identified during the post-drill critique were entered into the corrective action program with the appropriate significance characterization.
b. Findings
No findings of significance were identified.
1R07 Heat Sink Performance
a. Inspection Scope
The inspectors observed heat exchanger performance testing which utilized the periodic maintenance method for the jacket water and lube oil heat exchangers for the following:
- Emergency Diesel Generator 1-1 (Heat Exchangers E-22A and E-31A); and
- Emergency Diesel Generator 1-2 (Heat Exchangers E-22B and E-31B).
The inspectors verified the following items during the inspections:
C Tests conformed with the Licensees Generic Letter 89-13 Program for Heat Exchanger Inspections; C Inspection results were appropriately categorized against acceptance criteria and results were acceptable; C Frequency of inspection was sufficient to detect degradation; and C Conditions adverse to quality identified during the inspections were appropriately documented in the licensees corrective action system.
Portions of the heat exchanger tube inspections were observed by the inspectors. In addition, the inspectors observed the cleaning of heat exchanger tubes and verified that the methods used to inspect and clean the heat exchanger were adequate. Additionally, the as-found results of the inspection and testing were verified to be appropriately dispositioned before the system was returned to service.
b. Findings
No findings of significance were identified
1R11 Licensed Operator Requalification
a. Inspection Scope
The inspectors observed licensed operator performance during a simulator training session on November 20, 2002. The inspectors assessed the licensed operators ability to respond in accordance with applicable off-normal operating procedures and emergency operating procedures to the following plant equipment problems that were contained in the training scenario:
C pressurizer pressure safety channel failed low; C primary coolant system inadvertent dilution; C steam generator tube leak that subsequently resulted in a tube rupture; and C failure of safety injection to automatically initiate.
The inspectors observed the Shift Supervisor execute the emergency implementing procedures in response to the simulated plant conditions. The inspectors verified that the Shift Supervisor classified the emergency condition, and notified local authorities and the NRC in an accurate and timely manner. The inspectors also observed the post-scenario critique to assess the licensee evaluators ability to identify deficient operator performance.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed the licensees maintenance effectiveness for planned and emergent issues associated with the Critical Service Water System which was designated as having high safety significance within the licensees maintenance rule program.
The inspectors reviewed the licensees maintenance rule performance indicators to verify that the systems status had been characterized in the appropriate category within the licensees maintenance rule program. The inspectors reviewed work order histories and selected condition reports written against the system over the last 2 years to verify that maintenance and identified problems had been appropriately addressed.
Completed work orders were reviewed to determine if there was an adverse trend in system performance that could be attributed to inappropriate work practices and to determine if there were any common cause issues that had not been addressed.
Further, the inspectors reviewed selected condition reports and associated maintenance rule evaluations to verify that the identified problems were appropriately characterized and were dispositioned in accordance with the licensees maintenance rule program.
The inspectors also verified that designated corrective actions were reasonable and had been implemented as scheduled.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
a. Inspection Scope
The inspectors reviewed Operators Risk Reports, Shift Supervisor logs, and daily maintenance schedules to verify that equipment necessary to minimize plant risk was operable or available as required during planned and emergent maintenance activities.
The inspectors also conducted plant tours to verify that equipment necessary to minimize risk was available for use. The following seven activities were reviewed:
C Planned maintenance on Control Valve 3059, High Pressure Safety Injection Discharge to Train 1, on October 9, 2002, and emergent maintenance on control room boundary Door-16, Mechanical Equipment Room, on October 10-11, 2002; C Planned outage on Switchyard 345 KV Front-Bus and Component Cooling Water Pump P-52C on October 15-17, 2002; C Planned maintenance on Emergency Diesel Generator 1-2 on October 21-25, 2002; C Planned maintenance on Emergency Diesel Generator Fuel Oil Transfer Pumps on November 15, 2002; C Planned maintenance on Emergency Diesel Generator 1-1 on November 6-9, 2002; C Planned outage on Switchyard 345 KV Rear-Bus on November 26, 2002; and C Planned outage on component cooling water to the spent fuel pool cooling system on December 16-19, 2002.
The inspectors discussed plant configuration control for the maintenance activities with operations, maintenance and work control center staff to verify that work activities were appropriately controlled.
In addition, the inspectors reviewed select condition reports to verify that problems identified during the work activities were appropriately characterized and entered into the licensees corrective action program.
b. Findings
No findings of significance were identified.
1R14 Personnel Performance Related to Non-Routine Plant Evolutions and Events
a. Inspection Scope
The inspectors reviewed the plans, associated procedures and applicable work orders, and observed portions of the following four non-routine plant evolutions:
C transfer of water between the spent fuel pool and the safety injection refueling water storage tank on October 27, 2002, to validate the method as a contingent cooling mechanism for the spent fuel pool for upcoming planned maintenance; C troubleshooting D channel pressurizer high pressure input to reactor protection system pressurizer high pressure and thermal margin low pressure trips on November 4, 2002; C drain and subsequent fill of Safety Injection Tank 82D on November 11 and 12, 2002, to conduct emergent repairs to an unisolable leak from the level transmitter instrument line while at power; and C reopening of Main Turbine Stop Valve No. 1 that had inadvertently failed closed on December 5, 2002, with the plant at 33 percent power.
Regarding the transfer of water between the spent fuel pool and the safety injection refueling water storage tank evolution, the inspectors verified that the plans contained appropriate contingency actions and that the procedure steps adequately controlled the evolution. In addition, the inspectors verified that procedural actions and contingency plans were discussed during pre-evolution briefings.
For the troubleshooting activities on D channel pressurizer pressure input into the reactor protection system, the inspectors observed the pre-evolution brief to verify that potential problems and appropriate contingency actions were discussed. The inspectors also observed the troubleshooting activities by maintenance personnel in the control room to verify that the evolution was being appropriately controlled by the control room operators. The inspectors reviewed the associated work orders to verify that appropriate criteria was specified which the technicians could use to determine if a problem existed with the system components that were being analyzed.
Regarding the drain and subsequent fill of Safety Injection Tank 82D, the inspectors verified that the evolution was accomplished in accordance with Standard Operating Procedure -3, Safety Injection and Shutdown Cooling System. The inspectors also verified that the as left condition for Safety Injection Tank 82D met the requirements of Technical Specification 3.5.1, Safety Injection Tanks, surveillance requirements.
On December 6, 2002, the inspectors observed the pre-evolution brief and operator performance in the control room during the evolution to reopen Main Turbine Stop Valve No. 1 that inadvertently failed closed on December 5, 2002, when the plant was at 33 percent power. The inspectors also reviewed the procedure that was developed for the evolution. The inspectors verified that the operators completed the evolution in accordance with the developed procedure and that appropriate precautions, limitations and contingency actions were specified for the evolution. The inspectors also verified that the cause of the problem had been adequately addressed.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed four operability assessments as documented in the associated condition reports for the following risk significant plant equipment:
- D/G Cooling Fan Damper D-28 (V-24C);
- Component Cooling Water Pump P-52A;
- High Pressure Air System; and
The inspectors interviewed the cognizant engineers and reviewed the supporting documents to assess the adequacy of the operability assessments for the current plant Mode. The inspectors also reviewed the applicable sections of the Technical Specifications, Final Safety Analysis Report, and Design Basis Documents to verify that the operability assessments were technically adequate and that the components remained available, such that no unrecognized increase in plant risk had occurred.
b. Findings
No findings of significance were identified.
1R16 Operator Workarounds
a. Inspection Scope
The inspectors reviewed the operator challenges, operator workarounds, and control room deficiencies that were previously identified by licensee personnel to verify that the cumulative effects did not create significant adverse consequences regarding the reliability, availability and operation of accident mitigating systems. The inspectors also assessed the cumulative effects on the operators ability to implement abnormal and emergency response procedures to verify that the operators could respond to plant transients and accidents in a correct and timely manner.
The inspectors reviewed selected condition reports related to operator workarounds to verify that identified problems related to operator workarounds were entered into the corrective action program with the appropriate significance characterization. The inspectors also verified that identified corrective actions were reasonable and had been implemented as scheduled.
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications
a. Inspection Scope
The inspectors reviewed (newly developed) Standard Operating Procedure 3, Section 7.5.11, Safety Injection and Shutdown Cooling System, To Fill Safety Injection Tank and Outlet Piping Between the Check Valves with HPSI Pumps. The procedure was written to fill Safety Injection Tank T-82D on November 13, 2002, after it was drained to repair a non-isolable leak from an instrument line. The inspectors reviewed the associated 10 CFR 50.59 screening evaluation to verify that licensee personnel adequately evaluated the new procedure with respect to the design function of the safety injection tanks. The inspectors also reviewed the associated piping diagram to verify that the flowpaths aligned by the procedure would not adversely impact the safety injection tanks functional requirements during accident conditions.
b. Findings
No findings of significance were identified.
1R19 Post Maintenance Testing
a. Inspection Scope
The inspectors observed portions of post maintenance testing and reviewed documented testing activities following scheduled maintenance to determine whether the tests were performed as written. The inspectors also verified that applicable testing prerequisites were met prior to the start of the tests and that the effect of testing on plant conditions was adequately addressed by control room staff. The following four post maintenance test activities were reviewed:
C Emergency Diesel Generator 1-1, October 24 and 25; C Emergency Diesel Generator 1-2, November 8 and 9; C Repair of Broken Weld on 3/4 inch line from Safety Injection Tank T-82D November 12 and 13; and C Replacement of three component cooling water isolation valves to the spent fuel pool cooling heat exchangers, December 17 through 20.
The inspectors reviewed post maintenance testing criteria to verify that the test criteria was appropriate with respect to the scope of work performed and that the acceptance criteria were clear.
In addition, the inspectors reviewed the completed tests and procedures to verify that the tests adequately verified system operability. Documented test data was reviewed to verify that the data was complete and that the equipment met the procedure acceptance criteria, which demonstrated that the equipment was able to perform the intended safety functions.
Further, the inspectors reviewed condition reports regarding post maintenance testing activities to verify that identified problems were appropriately characterized.
b. Findings
No findings of significance were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
The inspectors reviewed daily work schedules and toured the plant on December 2nd and 3rd 2002, to verify plant equipment that operations personnel had designated as protected was appropriately controlled to minimize risk while the plant was on natural circulation cooling following the December 1, 2002, reactor trip. The inspectors also observed the following plant startup activities in the control room:
C start of first two primary coolant pumps on December 3, 2002; C reactor startup on December 4, 2002; and C main generator synchronization to the grid on December 5, 2002.
The inspectors observed the above activities to verify that reactivity changes and plant startup activities were appropriately controlled in accordance with technical specifications and plant procedures.
In addition, the inspectors reviewed condition reports related to the maintenance outage and subsequent plant startup activities to verify that the identified problems were entered into the corrective action program with the appropriate significance characterization.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors reviewed the following five surveillance testing activities conducted on risk-significant plant equipment:
C Auxiliary Feedwater System; C Transformer Deluge Systems Surveillance Test; C 5-Year Containment Tendon Surveillance; C Safety Injection; and C Local Leak Rate Test for Inner and Outer Personnel Air Lock Door Seals.
The inspectors observed portions of the testing in the plant to verify that testing was conducted in accordance with prescribed procedures. The inspectors also reviewed the documented test data for the Technical Specification Surveillance Test procedures and the associated basis documents to verify that testing acceptance criteria were satisfied.
In addition, the inspectors reviewed applicable portions of Technical Specifications, the Final Safety Analysis Report and Design Basis Documents to verify that the surveillance tests adequately demonstrated that system components could perform designated safety functions.
Further, the inspectors reviewed selected condition reports regarding surveillance testing activities to verify that the identified corrective actions were reasonable and had been implemented as scheduled.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the modification documentation and associated 10 CFR 50.59 evaluation for the following three temporary plant modifications:
- 2002-22, Accept removal of static wire from running between the main power transformer and the switchyard;
- 2002-15, Jumper out pressure switch PS-1036B to allow Primary Coolant Pump Oil Lift Pump P-81B to operate independent of the AC Oil Lift Pump pressure switch; and
- 2002-10, Turbine Intercept, Reheat and Main Stop Valve Test Solenoid Isolation In addition, the inspectors reviewed selected condition reports regarding temporary modifications to verify that identified problems were appropriately characterized.
The inspectors verified that the temporary modifications did not adversely impact other safety-related equipment and that the modifications were being controlled in accordance with Administrative Procedure 9.31, Temporary Modification Control, requirements.
b. Findings
No findings of significance were identified.
1EP6 Emergency Plan Drill Evaluation
a. Inspection Scope
The inspectors observed performance of emergency response personnel in the simulator control room and the technical support center, and reviewed event notification forms that were completed during a drill on December 11, 2002. The inspectors verified that emergency response personnel classified the event in an accurate and timely manner as prescribed in Emergency Implementing Procedure 1, Emergency Classifications and Actions, and that required notifications to State and Local Police authorities, and the NRC were completed in an accurate and timely manner as prescribed in Emergency Implementing Procedure 3, Communications and Notifications.
The inspectors also verified that the technical support center and operational support center on-site emergency facilities were activated within approximately 60 minutes after the Alert condition was classified as prescribed by the drill objectives.
The inspectors observed the post-drill critique in the Technical Support Center to verify that licensee evaluators adequately identified emergency response performance problems and reviewed the associated condition reports to verify that identified problems were appropriately characterized.
b. Findings
No findings of significance were identified.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01)
.1 Plant Walkdowns
a. Inspection Scope
The inspectors reviewed the radiological conditions of work areas within radiation areas and high radiation areas in the radiologically restricted area to verify the adequacy of radiological boundaries and postings. This included walkdowns of high and locked high radiation area boundaries in the Auxiliary Building and the Spent Fuel Pool. The inspectors performed independent measurements of area radiation levels and reviewed associated licensee controls to determine if the controls (i.e., surveys, postings, and barricades) were adequate to meet the requirements of 10 CFR Part 20 and the licensees Technical Specifications.
b. Findings
No findings of significance were identified.
2OS3 Radiation Monitoring Instrumentation (71121.03)
.1 Identification of Radiological Monitors Associated With High/Very High Radiation Areas
a. Inspection Scope
The inspectors completed walkdowns and reviewed calibration records to verify the accuracy and operability of radiation monitoring instruments used for the protection of occupational workers. Instrumentation included area radiation monitors (ARMs),continuous air monitors (CAMs), portable survey meters, portal monitors, and electronic dosimeters.
The Final Safety Analysis Report (FSAR) was reviewed to identify those ARMs and CAMs that were associated with transient high and very high radiation areas. These monitors included, but were not limited to, the following:
C Fuel Pool Area Monitor; C High Range Containment Monitor; and C Containment Atmosphere Gas Monitor.
The inspectors performed a walkdown of selected ARMs and CAMs in order to verify that locations were as described in the FSAR.
b. Findings
No findings of significance were identified.
.2 Respiratory Protection - Self-Contained Breathing Apparatus
a. Inspection Scope
The inspectors reviewed the status and surveillance records for self-contained breathing apparatus that was located in various areas onsite, including those units reserved for fire brigade and control room personnel. In addition, the inspectors reviewed the licensees training, mask fit, and medical qualification records to verify that applicable emergency response and control room personnel were currently trained and qualified in the use of self-contained breathing apparatus.
b. Findings
No findings of significance were identified.
.3 Problem Identification and Resolution
a. Inspection Scope
The inspectors reviewed self-assessments of the radiation monitoring instrumentation program, SCBA maintenance and user training, and the operation and calibration of the MGP Instruments CDM-21 Calibrator and DMC electronic dosimeters to evaluate the effectiveness of the self-assessment process to identify, characterize, and prioritize problems. The inspectors also reviewed corrective action documentation to verify that previous radiation monitoring and SCBA deficiencies were adequately addressed. The inspectors also reviewed the licensees year 2002 condition reports covering radiological incidents involving personnel internal contamination events and radiological instrumentation to verify that the licensee could identify, track, and correct radiological problems in these areas.
b. Findings
No findings of significance were identified.
SAFEGUARDS
Cornerstone: Physical Protection (PP)
1PP3 Response to Contingency Events (71130.03)
a. Inspection Scope
The inspectors reviewed the status of security operations and assessed licensee implementation of the protective measures in place as a result of the current, elevated threat environment.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES (OA)
4OA1 Performance Indicator Verification
a. Inspection Scope
The inspectors verified that the data submitted by the licensee was accurate and complete for the following three Performance Indicators:
- Unplanned Power Changes;
- Reactor Coolant System Leakrate; and
- Occupational Exposure Control Effectiveness.
The inspectors reviewed control room logs, licensee monthly operating reports, and licensees Incident Analysis System logs, to verify that the licensee had accurately reported the unplanned power changes performance indicator for October 2001 through October 2002.
Regarding the reactor coolant system leakrate performance indicator, the inspectors compared the data submitted to the NRC for the first three quarters of 2002 with the daily calculated leakrates documented in General Operating Procedure -13, 1, Primary Coolant System Inventory Form.
For the Occupational Exposure Control Effectiveness performance indicator, the inspectors verified the licensees assessment of its performance indicators for the previous four calendar quarters. No reportable elements were identified by the licensee for the 4th quarter of 2001 and the 1st, 2nd, and 3rd quarters of 2002. The inspectors reviewed 4th quarter 2001 and 1st, 2nd, and 3rd quarters of 2001 and 2002 condition reports to verify that there were no occurrences during those quarters.
Further, the inspectors verified that a condition report was generated at the appropriate significance level for an error that the inspectors identified in the reactor coolant system leakrate performance indicator data for May 2002 that was submitted to the NRC.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1 Failure of Mechanical Equipment Room Door 16
a. Inspection Scope
The inspectors reviewed the circumstances surrounding the emergent failure of Door-16, Mechanical Equipment Room, on October 10, 2002, which rendered the control room boundary inoperable and placed the plant in a resultant 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Technical Specification limiting condition for operation. The inspectors reviewed evaluations for condition reports that had been generated previously for Door-16 failures and assessed the identified corrective actions for effectiveness.
b. Findings
Introduction The inspectors determined that a self-revealed Green finding was associated with a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for the failure to promptly identify and correct problems regarding the operation of Mechanical Equipment Room Door-16. Consequently, on October 10, 2002, Door-16 failed in the open position which rendered the radiological barrier function for the control room inoperable.
Description On October 10, 2002, a security officer was trapped inside the Mechanical Equipment Room for approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> because Door-16 would not open. After licensee maintenance personnel subsequently opened Door-16 at 5:45 a.m., the doors lower locking pins failed in the closed position which prevented the door from being closed.
Consequently, the control room boundary was inoperable which rendered both trains of control room ventilation filtration inoperable. As a result, an unplanned entry into Technical Specification 3.7.10.B.2 required that the control room boundary be restored to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Maintenance personnel disassembled the door and based on the as found conditions, the inspectors concluded that the door had been degrading for a long time. The brackets that hold the locking pins rigid to allow the opening mechanism to extend and retract the pins were loose for the two top and two bottom pins. One fastener in each of the top two brackets and one fastener in each of the bottom two brackets had come completely out and the other fasteners were loose. The loose brackets resulted in one of the bottom two pins not being able to be retracted after the door was opened which also prevented the door from being closed.
Door-16 was subsequently repaired, satisfactorily tested to be functional and declared operable approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later and the technical specification limiting condition for operation was exited. The inspectors also determined that administrative requirements regarding minimum manning for security personnel were met while the one security officer was trapped inside the room. Therefore, there were no technical specification or minimum staffing requirements for security personnel violated during this emergent issue.
However, the inspectors noted that several condition reports had been generated in the recent past for problems experienced while operating Door-16. The following four condition reports had been generated since August 2002 regarding Door-16 problems:
C CAP031011, Mechanical Equipment Room (Door 16) Failure, initiated on August 22, 2002; C CAP031099, Locked Inside Door-16 HVAC (Heating Ventilation and Air Conditioning) Area, initiated on August 29, 2002; C CAP031121, Inability to Open Control Room HVAC Door-16 initiated on September 1, 2002; and C CAP031479, Door-16 Control Room HVAC Door Stuck Closed, initiated on October 1, 2002.
Licensee personnel had completed condition evaluations for three of the above four condition reports prior to Door-16 failing on October 10, 2002. The inspectors noted that the condition evaluations for CAP031011 and CAP031121 were the same as the condition evaluation that was completed for CAP031099. For all three condition reports, the evaluation concluded that the door was not being operated properly in that licensee personnel were opening and closing the door with the locking pins not fully retracted as evidenced by scrape marks on the door sill. The evaluation further stated that improper operation of Door-16 was a theory which had not been proven and as a consequence the evaluation concluded that there was no known cause for the locking pins to not be fully retracted when opening and closing the door. However, no additional investigations had been done to either prove or disprove the theory that the door was being operated improperly. Therefore, the inspectors concluded that the evaluations completed for Condition Reports CAP031011 and CAP031121 were narrowly focused in that no additional investigations were conducted when the problem repeated.
The inspectors also concluded that corrective actions taken for the condition reports generated after the initially identified problem repeated were not appropriate.
Specifically, the corrective actions focused only on training plant personnel on how to operate Door-16 properly including posting written instructions on the door.
The inspectors concluded that the narrowly focused evaluations and corrective actions for the three problems identified since August 2002, regarding Door-16 were missed opportunities for licensee personnel to identify the cause of the problem. Consequently, licensee personnel did not investigate or troubleshoot potential problems associated with the operating mechanism until the issue was self-revealed on October 10, 2002, when Door-16 was opened and could not be closed.
The failure to promptly identify and fix the problems that plant personnel had experienced with operating Door-16 was considered a performance deficiency warranting a significance evaluation.
Analysis The inspectors determined that this finding was greater than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on April 29, 2002, because if left uncorrected it would become a more significant safety concern.
Specifically, after Door-16 failed in the open position, the control room boundary was rendered inoperable which rendered both trains of control room ventilation filtration inoperable. Consequently, following a postulated uncontrolled release of radioactivity, the control room ventilation filtration system could not provide the radiological barrier function for the control room operators. In addition, Technical Specification 3.7.10.B.2 required the control room boundary to be restored to an operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and if not restored, then a plant shutdown to Mode 3 would be required within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
The inspectors evaluated the finding using Manual Chapter 0609, Significance Determination Process, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, Phase 1 screening. The inspectors determined that the barrier integrity cornerstone was adversely impacted and that the finding represented a degradation of only the radiological barrier function for the control room. Therefore, the finding was determined to be of very low safety significance (Green).
Enforcement 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, requires in part that measures be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to this, the evaluation and corrective actions for several condition reports that had been generated by licensee personnel regarding problems experienced with operating Door-16 were not effective in identifying or correcting the problems with operating Door-16. Consequently, on October 10, 2002, Door-16 failed in the open position which rendered the radiological barrier function for the control room inoperable.
This violation is associated with a self-revealing finding that is characterized by the significance determination process as having very low safety significance (Green) and is being treated as a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 50-255/02-09-01)
This issue was entered in the licensees corrective action program as Condition Report CAP031618, Door-16 Mechanical Equipment Room Failure Results in Technical Specification 3.7.10.A/B Entry.
.2 Root Cause Evaluation For Automatic Plant Trip on December 1, 2002
a. Inspection Scope
The inspectors reviewed the root cause evaluation for Condition Report CAP032289, Automatic Reactor Trip and AFAS (Auxiliary Feedwater Actuation Signal) Actuation, that was generated following the reactor trip on December 1, 2002. The inspectors verified that the root cause evaluation contained the following attributes:
C consideration of extent of condition, generic implications, common cause and previous occurrences; C root and contributing causes of the problem were identified; C identified corrective actions were appropriately focused to correct the problem and were completed in a timely manner commensurate with the safety significance of the issue; and C implementation of longer term corrective actions were reasonable.
On December 18, 2002, the inspectors observed the Corrective Action Review Board meeting that discussed the root cause evaluation to assess the effectiveness of the review boards members in evaluating completed root cause evaluations.
b. Findings
Introduction The inspectors determined that a self-revealed Green finding was associated with a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for the failure to rigorously evaluate operating experience which resulted in inadequate preventive maintenance activities being developed for the 345 Kilo-Volt (KV)transmission lines that connect the plant and the switchyard. Consequently, on December 1, 2002, a connector holding a static wire on the 345 KV transmission line towers between the plant and the switchyard failed, and the static line contacted one phase of the 345 KV lines and all three phases of the 345 KV Rear Bus in the switchyard which resulted in an automatic plant trip on loss of generator load and a loss of startup power.
Description On December 1, 2002, at 9:54 p.m. an automatic reactor trip from 100 percent power occurred. The trip occurred when a static line on the 345 KV transmission line towers, which is used for lightning protection, fell and contacted one phase of the 345 KV lines that connected the main generator output to the switchyard. During the root cause evaluation, licensee personnel developed the following sequence of events:
C the static line hanger dog-bone that connected the static line to transmission line Tower Number 2 failed at the connection point to the tower. (For reference purposes, there were four towers that carried the transmission lines to the switchyard. Tower Number 4 was closest to the plant and Tower Number 1 was closest to the switchyard);
C after the static line released from Tower Number 2, the additional weight between Towers 1 and 3 caused the dog-bone to fail on Tower Number 1; C with the two connectors failed, the static line sagged and contacted the X phase of the 345 KV transmission lines between Towers 2 and 3; C the energy from the 345 KV line vaporized a section of the static line near Tower Number 3 and caused a loss of load (345 KV to ground) signal to trip the main generator output breaker and a resultant signal from the reactor protection system to trip the reactor; C the trip signal initiated a fast transfer of non-safety related 4160 volt electrical busses A, B, G, and E from station power to startup power as designed; C approximately 2 seconds after the plant trip signal, the severed static line fell to the ground from Towers 1 and 2 and contacted all three phases of the 345 KV Rear Bus in the switchyard; C a fault to ground resulted when the static line contacted the 345 KV Rear Bus and the breakers in the switchyard opened, as designed, to clear the fault which resulted in the loss of Rear Bus; C the loss of Rear Bus resulted in the loss of startup power to the plant which caused the subsequent loss of power to non-safety related 4160 Volt electrical busses A, B, G and E; C loss of 4160 Volt electrical busses A, B, G and E resulted in the loss of several non-safety related plant components including the primary coolant pumps; C with the loss of primary coolant pumps, the plant was on natural circulation cooling.
The plant remained stable throughout the event and all safety-related equipment operated as designed. The plant was maintained at or near normal operating pressure and temperature while on natural circulation cooling with heat removal being accomplished with the auxiliary feedwater system and the steam generator atmospheric dump valves. The plant remained on natural circulation cooling until two primary coolant pumps were started on December 3, 2002, after licensee personnel completed necessary troubleshooting and repairs. (The plant trip is also discussed in Section 4OA3.1 of this report)
The inspectors concluded that the root cause evaluation thoroughly evaluated the sequence of events and causes of the plant trip, and that immediate corrective actions taken and planned longer term corrective actions were reasonable.
However, the inspectors noted that the root cause evaluation determined that prior industry operating experience was not rigorously evaluated. The available operating experience indicated that the licensee needed to verify that plant was fully responsible for switchyard high voltage grid equipment and that the equipment was fully incorporated into the preventive maintenance program.
Following the receipt and evaluation of the operating experience information, licensee personnel developed preventive maintenance inspections of the 345 KV lines, towers and transformers between the plant and the switchyard. The inspectors verified that the preventive maintenance activities had been accomplished as required.
However, licensee personnel failed to identify all the transmission line components that required routine preventive inspections to ensure system reliability. Therefore, no preventive maintenance activities were developed for the static line hanger dog-bone connectors. Consequently, the dog-bone connectors degraded during the 30-year service life undetected until the problem was self-revealed on December 1, 2002, when the two dog-bone connectors failed. Other dog-bone connectors that were inspected as part of the corrective actions were also found to be severely degraded. Therefore, the root cause evaluation concluded that the static line dog-bone connector failed because of inadequate preventive maintenance activities.
Licensee personnel replaced all the severely degraded dog-bone connectors on Towers 1 through 4 prior to plant restart. However, the failure to rigorously review available operating experience and ensure that adequate preventive maintenance for the 345 KV transmission lines between the plant and the switchyard was implemented was a licensee performance deficiency warranting a significance evaluation.
Analysis The inspectors determined that this finding was greater than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on April 29, 2002. The finding was related to the initiating events cornerstone attribute regarding procedure adequacy, and the cornerstone objective of limiting events that upset plant stability and challenge critical safety functions during power operations was affected.
Specifically, the inadequate preventive maintenance procedure associated with the 345 KV transmission line towers resulted in undetected degradation of the static line dog-bone connectors. Consequently, the connectors failed which resulted in a plant trip from 100 percent power and a loss of forced circulation cooling.
The inspectors evaluated the finding using Manual Chapter 0609, Significance Determination Process, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, Phase 1 screening. The inspectors determined that the initiating events cornerstone was adversely impacted and that the finding:
C did not contribute to the likelihood of a primary or secondary system loss of coolant accident initiator; C did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available; and C did not increase the likelihood of a fire or a flood.
Therefore, the finding was determined to be of very low safety significance (Green).
Enforcement 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, requires in part that measures be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to this, the failure to rigorously evaluate available operating experience precluded the development of adequate preventive maintenance inspections of the static line hanger dog-bone connectors on the 345 KV transmission line towers that the plant was responsible for. Consequently, the dog-bone connectors degraded undetected until two failed which caused a plant trip from 100 percent power and a loss of forced circulation cooling.
This violation is associated with a self-revealed finding that is characterized by the significance determination process as having very low safety significance (Green) and is being treated as a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 50-255/02-09-02)
This issue was entered in the licensees corrective action program as Condition Report CAP032289, Automatic Reactor Trip and Auxiliary Feedwater Actuation Signal Actuation.
.3 Evaluation of Operating Experience Information
a. Inspection Scope
The inspectors reviewed the condition report evaluation for CIED0202545, Evaluation of Prairie Island Non-Seismic Service Water Piping for Applicability. The inspectors verified the following attributes were adequately addressed in the evaluation:
C generic implications to Palisades and related extent of condition; C classification and prioritization of the problem and associated resolution, as necessary, were commensurate with safety significance; and C needed corrective actions were properly focused.
b. Findings
No findings of significance were identified.
4OA3 Event Follow-up
.1 Automatic Plant Trip on December 1, 2002
a. Inspection Scope
The inspectors responded to the site after being notified that the plant had automatically tripped on loss of generator load at 9:54 p.m. on December 1, 2002. The inspectors walked down the control room panels noting system indications to verify that plant conditions were stable and that safety-related mitigation equipment was available. The inspectors also verified that appropriate emergency operating procedures were being implemented.
The inspectors reviewed the post event review report and control room logs to verify that plant equipment operated as designed and that control room operators responded in accordance with applicable emergency operating procedures. The inspectors also reviewed the associated 4-hour non-emergency report, Event Notification 39414, to verify licensee personnel communicated the plant trip in an accurate and timely manner in accordance with 10 CFR 50.72.
On December 3, 2002, the inspectors observed the Management Review Board meeting regarding the plant trip to verify that licensee personnel understood the reason for the plant trip. The inspectors also observed the Special Restart Plant Review Committee meeting on December 4, 2002, to verify that previously identified plant equipment problems had been corrected to minimize plant risk and to ensure that no nuclear safety concerns existed prior to plant restart activities commenced.
The inspectors verified that the cause of the trip was understood and an NRC Region III Senior Reactor Analyst reviewed the trip from a risk perspective and concluded that the event was of very low risk. Also, the inspectors and the Senior Reactor Analyst verified that the trip did not meet the threshold to warrant a Special Inspection in accordance with Management Directive 8.3, NRC Incident Investigation Program.
Further, the inspectors reviewed condition reports generated as a result of the plant trip to assess problem characterization and reviewed the root cause evaluation for the plant trip which is discussed further in Section 4OA2.2 of this report.
b. Findings
No findings of significance were identified.
.2 (Closed) Licensee Event Report (LER) 02-001: Noncompliance With Technical
Specification Requirements for Safety Injection Tank T-82D
a. Inspection Scope
The inspectors reviewed Licensee Event Report 02-001, Noncompliance With Technical Specification Requirements for Safety Injection Tank T-82D, to verify that the event was accurately described and to assess the appropriateness of identified corrective actions.
b. Findings
On November 11, 2002, with the plant operating at 100 percent power, operations personnel identified that the level in Safety Injection Tank T-82D was lowering slowly.
During a subsequent containment entry, operations personnel identified a non-isolable leak on a weld from the 3/4 inch piping side of a sock-o-let which attached the lower sensing line for Level Transmitter LT-0374 to the main 12 inch downcomer from T-82D.
Consequently, Safety Injection Tank T-82D was declared inoperable at 1:45 p.m. and Technical Specification 3.5.1.B was entered which required that T-82D be returned to an operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Technical Specification 3.5.1 required four safety injection tanks to be operable in Modes 1 and 2. If T-82D was not returned to an operable status within the allowed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> then additional actions per Technical Specification 3.5.1.C required the plant to be shut down to Mode 3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
License personnel subsequently reduced plant power to 60 percent to conduct repairs.
However, licensee personnel determined that repairs could not be completed within the Technical Specification allowed outage time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Therefore, on November 12, 2002, Nuclear Management Company, LLC, verbally requested and received enforcement discretion from the NRC to extend the allowed outage time of Technical Specification 3.5.1.B by 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 1:45 p.m. on November 13, 2002.
Consequently, Technical Specification 3.5.1.B allowed outage time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was knowingly exceeded under an approved Notice of Enforcement Discretion which caused this event. The leak was subsequently repaired within the extended allowed time and T-82D was declared operable at 5:25 a.m. on November 13, 2002.
The inspectors concluded that the LER accurately described the event and therefore, this LER is closed.
However, the inspectors identified a finding of very low safety significance (Green) and associated Non-Cited Violation during a review of the root cause evaluation for the leak on Safety Injection Tank T-82D which are discussed in Section 4OA5.1 of this report.
4OA5 Other Activities
.1 (Closed) Unresolved Item 50-255/02-09-03: Review of Notice of Enforcement
Discretion (NOED) 02-3-059 For Nuclear Management Company LLC Regarding Palisades
a. Inspection Scope
(71152)
The inspectors reviewed the circumstances associated with issuing NOED 02-3-059 on November 12, 2002, to extend the allowed outage time for Technical Specification 3.5.1, Safety Injection Tanks, for the inoperable Safety Injection Tank T-82D. The inspectors reviewed the basis for the licensee's NOED request and verified that licensee personnel complied with the compensatory actions noted in the NOED.
The inspectors also reviewed the root cause evaluation for the problem as documented in Condition Report CAP032073, T-82D, Safety Injection Tank Level Instrument Line Leak, which required entry into the Technical Specification Limiting Condition for Operation on November 11, 2002, to determine if a failure to comply with regulatory requirements contributed to the need for enforcement discretion. The inspectors verified that the root cause evaluation adequately addressed the following attributes:
C consideration of extent of condition, generic implications, common cause and previous occurrences; C root and contributing causes of the problem were identified; C identified corrective actions were appropriately focused to correct the problem and were completed in a timely manner commensurate with the safety significance of the issue; and C implementation of longer term corrective actions were reasonable.
On December 18, 2002, the inspectors also observed the Corrective Action Review Board meeting that discussed the root cause evaluation to assess the effectiveness of the review boards members in evaluating completed root cause evaluations.
b. Findings
Introduction No findings of significance were identified during the inspectors review of the basis of the NOED request, and the licensee's implementation of compensatory actions required by the NOED.
However, the inspectors determined that a self-revealed Green finding was associated with a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, for the failure to adequately evaluate the root cause in 1992 of a leak that occurred on the instrument line for Safety Injection Tank T-82D. Consequently, past corrective actions were not adequate to prevent the leak from recurring on November 11, 2002. As a result, T-82D was rendered inoperable and unavailable to perform the intended safety function of injecting borated water to the reactor during a large break loss of coolant accident. In addition, a NOED had to be issued to extend Technical Specification Limiting Condition 3.5.1, Safety Injection Tanks, allowed outage time by 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> so that repairs could be completed to restore T-82D to an operable status without having to shut down the plant.
Description On November 11, 2002, with the plant operating at 100 percent power, operations personnel identified that the level in Safety Injection Tank T-82D was lowering slowly.
During a subsequent containment entry, operations personnel identified a non-isolable leak on a weld from the 3/4 inch piping side of a sock-o-let which attached the lower sensing line for Level Transmitter LT-0374 to the main 12 inch downcomer from T-82D.
Consequently, Safety Injection Tank T-82D was declared inoperable at 1:45 p.m. and Technical Specification 3.5.1.B was entered which required that T-82D be returned to an operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Technical Specification 3.5.1 required four safety injection tanks to be operable in Modes 1 and 2. If T-82D was not returned to an operable status within the allowed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> then additional actions per Technical Specification 3.5.1.C required the plant to be shut down to Mode 3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Plant power was subsequently reduced to 60 percent to conduct repairs. However, licensee personnel determined that repairs could not be completed within the Technical Specification allowed outage time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Therefore, on November 12, 2002, Nuclear Management Company, LLC, verbally requested and received enforcement discretion from the NRC to extend the allowed outage time of Technical Specification 3.5.1.B by 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 1:45 p.m. on November 13, 2002. The leak was subsequently repaired within the extended allowed outage time and T-82D was declared operable at 5:25 a.m. on November 13, 2002.
The inspectors reviewed the licensee's NOED request to assess the qualitative and quantitative basis for the extension to Technical Specification 3.5.1.B allowed outage time. For the request, licensee personnel indicated that there was no net increase in risk by allowing the plant to operate for an additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while repairs were completed to restore T-82D to an operable status and that the action did not result in an undue risk to the health and safety of the public.
The specific evaluation to determine plant risk was performed using the Palisades probabilistic risk assessment model that accounted for the current plant configuration and included the assumption that the low pressure safety injection system, the high pressure safety injection system and the remaining three safety injection tanks remained available. The results of the evaluation indicated an increase in the core damage probability, over the baseline configuration, of 4E-11 which was significantly less than the increase in core damage probability associated with a plant shut down which had been estimated to be 1E-06 for Palisades.
At the time that the NOED was granted, the inspectors verified that the low pressure safety injection system, the high pressure safety injection system and the remaining three safety injection tanks were operable. The inspectors concluded that the basis for the licensee's NOED request was adequately supported. Additionally, the inspectors determined that the compensatory actions noted in the NOED were reasonable and had been implemented as described.
The inspectors concluded that the root cause evaluation thoroughly addressed extent of condition, generic implications and common causes, and that reasonable root and contributing causes were identified. The inspectors also concluded that the completed corrective actions were appropriate and the schedule to complete longer term corrective actions was reasonable.
Regarding previous occurrences, the inspectors noted that the root cause evaluation discussed a leak on the same instrument line for Safety Injection Tank T-82D that had occurred in 1992. The evaluation conducted in 1992 concluded that the leak was due to a boric acid attack to a chromium-deficient area that made the joint vulnerable to corrosion. However, the root cause evaluation for the leak that occurred on November 11, 2002, identified several problems with the 1992 evaluation including the following:
C there was no apparent data that demonstrated a chromium deficiency existed; and C no metallurgical examination was performed to confirm or refute the potential failure modes that had been identified.
Therefore, the evaluation for the leak that occurred on November 11, 2002, concluded that the root cause evaluation completed in 1992 for the previous leak was completed without adequate information and that the conclusions were incorrect.
In addition, the evaluation for the leak that occurred on November 11, 2002, concluded that the root cause of the leak, as well as the previous leak in 1992, was high cycle vibration imposed upon a susceptible piping configuration. This conclusion was based on additional information, including metallurgical examination data, that was obtained during the evaluation.
Consequently, the inspectors concluded that the NOED was necessitated by the failure to identify the cause of the leak that occurred in 1992. As a result, the associated corrective actions taken in 1992 were inadequate to prevent the leak from recurring which was considered a licensee performance deficiency that warranted a significance evaluation.
Analysis The inspectors determined that this finding was greater than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on April 29, 2002. The finding was related to the mitigation systems cornerstone attribute regarding equipment performance. The cornerstone objective to ensure the availability of systems that respond to initiating events to prevent undesirable consequences was adversely affected by this finding.
Specifically, the inadequate root cause evaluation for the leak from T-82D level instrument line completed in 1992 precluded the implementation of adequate corrective actions. Consequently, the instrument line leak recurred on November 11, 2002, which rendered T-82D inoperable and unavailable to perform the intended safety function of injecting borated water to the reactor during a large break loss of coolant accident.
The inspectors evaluated the finding using Manual Chapter 0609, Significance Determination Process, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, Phase 1 screening. The inspectors determined that the mitigation systems cornerstone was adversely impacted and that the finding:
C was not a design or qualification deficiency confirmed not to result in loss of function per Generic Letter 91-18; and C did not represent an actual loss of the systems safety function.
However, the finding did represent an actual loss of safety function of a single train for greater than the Technical Specification allowed outage time. Therefore, the inspectors completed a Phase 2 analysis using Manual Chapter 0609, and the Risk-Informed Inspection Notebook for Palisades Nuclear Plant, Revision 1, which determined the following:
C the safety injection tanks were only credited for large break loss of coolant accidents; and C the exposure time for the inoperable safety injection tank was less than 3 days.
As a result, the initiating event likelihood as per Risk-Informed Inspection Notebook for Palisades Nuclear Plant, Revision 1, Table 1, Categories of Initiating Events for Palisades Power Plant, was very low. In addition, all other mitigating equipment for a large break loss of coolant accident was available when T-82D was inoperable.
Therefore, the finding was determined to be of very low safety significance (Green) in accordance with Manual Chapter 0609, Appendix A, Table 4, Risk Significance Estimation Matrix.
Enforcement 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, requires, in part, for significant conditions adverse to quality that measures shall be established to assure the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to this, licensee personnel failed to determine the cause of a leak in 1992 from the instrument line on Safety Injection Tank T-82D. Consequently, appropriate corrective actions were not taken and on November 11, 2002, the leak recurred.
This violation is associated with a self-revealed finding that is characterized by the significance determination process as having very low safety significance (Green) and is being treated as a Non-Cited Violation of 10 CFR 50 Appendix B, Criterion XVI, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 50-255/02-09-04)
This issue was entered in the licensees corrective action program as Condition Report CAP032073, T-82D Level Instrument Line Leak.
Also, the inspectors had opened URI 50-255/02-09-03 to track the root cause evaluation for the problem that necessitated the NOED request, NOED approval basis, and verification activities. Because the root cause evaluation for the problem that required the NOED was reviewed and a finding of very low safety significance was identified with an associated Non-Cited Violation as noted above, this URI is closed.
.2 (Closed) Unresolved Item (URI) 50-255/02-03-01: Inadequate Procedure for Tornado
Mitigation In NRC Inspection Report 50-255/02-03, Section 1R21.b.1, NRC inspectors documented an apparent violation of Technical Specification 5.4.1, which involved an inadequate emergency operating procedure (EOP). Based on information available during the inspection, the inspectors determined that the EOP for supplying auxiliary feedwater from backup water sources could not be completed by operators in a timely manner to mitigate certain tornado events. During the inspection, licensee personnel estimated that it would take approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to align and vent the backup system to supply the auxiliary feedwater system if the condensate storage tank was lost due to a tornado.
Estimated times had to be provided since licensee personnel had not previously validated the time necessary to complete the actions.
At the end of the inspection, this issue was characterized as a finding that had a credible impact on safety, in that performing the EOP as written would have resulted in a lack of timely restoration of auxiliary feedwater and a loss of all core cooling during certain tornado events. Specifically, the inspectors concluded, based on available information, that backup water sources would not be able to be aligned prior to losing the steam generators as a heat sink for a postulated tornado that resulted in the loss of the condensate storage tank and the safety injection refueling water storage tank.
However, the safety significance of the finding was unresolved pending NRC determination of the risk involved which would include an analysis of:
- (1) the probability of a tornado striking the plant and causing a loss of the condensate storage tank, safety injection and refueling water tank, and offsite power; and
- (2) the credit to be given for certain unproceduralized operator recovery actions.
To determine the risk involved, the inspectors and an NRC Region III Senior Risk Analyst reviewed the following additional information that licensee personnel had completed in response to this issue:
C Evaluation of Condition Report CPAL0201930, Impact to Performance Time Limit Not Validated in Emergency Operating Procedure Revision; C Engineering Analysis EA-SGK-02-001, Evaluation of the Impact of a Loss of Condensate Storage Tank on the Auxiliary Feedwater Pumps; and C Engineering Analysis EA-PSA-Tornado-02-07, Potential Core Damage Impact Due to a Tornado.
The condition report evaluation for CPAL0201930 included a validated timeline to align and vent the backup systems to supply the auxiliary feedwater system. The validation concluded that it would take approximately 23 minutes to align and vent either the service water backup to supply Auxiliary Feedwater Pump P-8C or to align and vent the fire protection backup to supply Auxiliary Feedwater Pumps P-8A and P-8B.
Consequently, the resultant time to complete initial emergency operating procedure actions and to align and vent a backup system for auxiliary feedwater could be accomplished within approximately 43 minutes. Therefore, the evaluation subsequently concluded that a backup system could be aligned and vented to supply auxiliary feedwater prior to the time at which the steam generators would be lost as a heat sink.
Engineering Analysis EA-SGK-02-001, concluded that venting would not be required when aligning the service water system or fire protection system as backup sources to supply auxiliary feedwater. Therefore, the time to align a backup supply to the auxiliary feedwater system if the condensate storage tank was lost from a tornado would be reduced further.
In addition, Engineering Analysis EA-PSA-Tornado-02-07, used the Palisades Probabilistic Safety Assessment to assess the potential impact on the core damage frequency for a postulated tornado at Palisades. The analysis concluded that the calculated core damage frequency was 8.7E-7 per year which was low risk.
Based on reviewing the new information provided by licensee personnel in response to this issue, the inspectors and the Senior Reactor Analyst concluded that this finding was of minor significance. Therefore, URI 50-255/02-03-01 is closed.
.3 Completion of Appendix A to TI 2515/148, Revision 1
The inspectors completed the pre-inspection audit for interim compensatory measures at nuclear power plants, dated September 13, 2002.
4OA6 Meetings
.1 Exit Meeting
The inspectors presented the inspection results to Mr. D. Cooper and other members of licensee management on January 7, 2003. Licensee personnel acknowledged the findings presented. The inspectors asked licensee personnel whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
.2 Interim Exit Meetings
The following Interim Exit Meetings were conducted:
C Radiation Protection inspection with Mr. D. Malone on November 21, 2002.
C Safeguards pre-inspection audit with Mr. B. Rowland on November 22, 2002.
KEY POINTS OF CONTACT Licensee D. Cooper, Site Vice President P. Harden, Director, Engineering N. Haskell, Nuclear Oversight Manager G.W. Hettel, Manager, Maintenance and Construction L. Lahti, Licensing Manager D. G. Malone, Supervisor, Regulatory Assurance D. J. Malone, General Plant Manager G. Packard, Operations Manager E. Weinkam, Director Regulatory and Strategic Issues R. Remus, Assistant Plant Manager B. Rowland, Security Manager P. Russell, Manager Performance Improvement NRC J. Eads, Project Manager, NRR J. Creed, Branch Chief, Safeguards LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-255/02-09-01 NCV Failure to promptly identify and correct problems regarding the operation of Mechanical Equipment Room Door-16 50-255/02-09-02 NCV Failure to rigorously evaluate industry operating experience information which resulted in inadequate preventive maintenance activities being developed for the 345 KV transmission lines that connect the plant with the switchyard 50-255/02-09-03 URI Review of Notice of Enforcement Discretion (NOED) 02-3-059 For Nuclear Management Company, LLC, Regarding Palisades 50-255/02-09-04 NCV Failure to adequately evaluate the root cause of a leak in 1992 on the instrument line for Safety Injection Tank T-82D which precluded adequate corrective actions to prevent repetition Closed 50-255/02-09-01 NCV Failure to promptly identify and correct problems regarding the operation of Mechanical Equipment Room Door-16 50-255/02-09-02 NCV Failure to rigorously evaluate industry operating experience information which resulted in inadequate preventive maintenance activities being developed for the 345 KV transmission lines that connect the plant with the switchyard 50-255/02-09-03 URI Review of Notice of Enforcement Discretion (NOED) 02-3-059 For Nuclear Management Company, LLC, Regarding Palisades 50-255/02-09- 04 NCV Failure to adequately evaluate the root cause of a leak in 1992 on the instrument line for Safety Injection Tank T-82D which precluded adequate corrective actions to prevent repetition 50-255/02-03-01 URI Inadequate Procedure for Tornado Mitigation 50-255/02-001 LER Noncompliance With Technical Specification Requirements for Safety Injection Tank T-82D LIST OF ACRONYMS USED AA Access Authorization ARM Area Radiation Monitor CAM Continuous Air Monitor CBOP Continuous Behavior Observation Program CFR Code of Federal Regulations CR Condition Report DRP Division of Reactor Projects DRS Division of Reactor Safety FSAR Final Safety Analysis Report HSAS Homeland Security Advisory System LER Licensee Event Report NCV Non-Cited Violation NMC Nuclear Management Company NOED Notice of Enforcement Discretion NRC Nuclear Regulatory Commission OHS Office of Homeland Security RCS Reactor Coolant System RIS Regulatory Information Summary SCBA Self-Contained Breathing Apparatus SDP Significance Determination Process SM&CS System Maintenance and Construction Services LIST OF
DOCUMENTS REVIEWED
1R01 Adverse Weather Protection
Plant Procedures
ONP-12 Off-Normal Procedure, Acts of Nature Revision 17
SOP-23 Plant Heating System Revision 17
SOP-23, Cold Weather Checklist Revision 17
SOP-23, Cold Weather Checklist - Electrical Revision 16
Miscellaneous Documents
Murray and Trettel Storm Warning October 4, 2002
Design Basis Service Water System Revision 6
Document 1.02
Final Safety General Climatology of Palisades Plant Area, Revision 23
Analysis Report Emergency Power Sources, Service Water
Sections 2.5.1, System, Auxiliary Feedwater System, HVAC
8.4, 9.1, 9.7, 9.8, System, and Turbine Building and Intake
5.9.4 Structure
Technical Service Water System Amendment 199
Specifications and
Bases for LCO 3.7.8
1R04 Equipment Alignment
Plant Procedures
AP-4.00 Operations Organization, Responsibilities, and Revision 23
Conduct
AP-4.02 Control of Equipment Revision 18
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP032053 Improper Storage of Ladders at Station Nos. 8
and 51 in West Engineered Safeguards Room
CAP032055 High Pressure Safety Injection Pump P-66A Seal
Cooling heat Exchanger Missing Bolt
1R05 Fire Protection
Plant Procedures
FP-MS-1 Fire Protection Check Sheet - Monthly Inspection Revision 2
and Testing of Fire Doors for Fire Areas 21, 28
FPSP-SI-1 Data Sheet for Alarm Bells and Ionization Smoke Revision 2
Detectors for Fire Areas 28, 30, 31
FPSP-RP-11 Fire Barrier Penetration Seal/Conduit Seal Revision 4
Inspection Form for Fire Areas 7, 21, 28, 30, 31
FPSP-SO-2 Safety-Related Fire Door Data Sheet for Fire Revision 0
Areas 7, 28
ONP-12 Off-Normal Procedure - Acts of Nature Revision 17
AP-4.02 Administrative Procedure - Control of Equipment Revision 18
ONP-25.1 Off-Normal Procedure - Fire Which Threatens Revision 11
Safety-Related Equipment
ONP25.2 Off-Normal Procedure - Alternate Safe Shutdown Revision 17
Procedure
FP-MS-1 Fire Protection Check Sheet Monthly Inspection Revision 2
and Testing of Fire Doors
FPSP-MO-1, Fire Suppression Water System Valve Alignment Revision 2
Verification Checkoff Sheet
FPSP-MO-2, Fire Hose Reel Station and Fire Hose Rack Revision 0
Station Checkoff Sheet
FPSP-AO-2, Fire Suppression Water System Fire Valve Revision 3
Operation Data Sheet
FPIP-6 Fire Suppression Training Revision 9
FPIP-3 Plant Fire Brigade Revision 8
FPSP-RO-9, Electrical Equipment Room #725 Sprinkler Head Revision 0
10 Locations
Miscellaneous Documents
EA-PSSA-00-001 Palisades Plant Post Fire Safe Shutdown Revision 1
Summary Report, for Fire Areas 12, 28
Palisades Plant Analysis for Fire Areas 28 Revision 4
Fire Hazards
Analysis
Palisades Plant Analysis for Fire Areas 11 & 12 Revision 4
Fire Hazards
Analysis
BTP ASB 9.5-1 U.S. NRC Branch Technical Position 9.5-1 - Revision 1
Guidelines for Fire Protection for Nuclear Power
Plants
Consumer Power Company - List of Changes Revision 2
and Response to Appendix A to Branch August 24, 1996
Technical Position APCSB 9.5-1 and Regulatory
Guides 1.78 and 1.101
FSAR 9.6 Final Safety Analysis Report, Section 9.6 - Fire Revision 23
Protection
Scenario and objectives, and the post-drill
critique for unannounced fire drill on
October 23, 2002
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP031809 Security Response to Fire May Have Adverse
Safety Repercussions
CAP031910 Evaluate Process to Account for Offsite
Emergency Responders After Response
CAP032065 NRC Questions With Regard to Safeguards
Equipment - NRC Safeguards Walkdown
CAP032369 Insulation Material not Properly Categorized
Leading to Missed Combustible Loading
1R07 Heat Sink Performance
EPS-M-15 Diesel Generator 1-2 - Refueling Frequency Revision 2
Maintenance
EPS-M-14 Diesel Generator 1-1 - Refueling Frequency Revision 3
Maintenance
EAR-99-0270 Gasket Material/Size Change for Lube Oil and
Jacket Water Heat Exchanger K-6A/B
WO 24212951 K-6A, Perform Selected Portions of EPS-M-14
MI-17022 ALCO Bulletin - Type CP and CPR Heat November 1963
exchangers
EM-09-16 Heat Exchanger Condition Assessment Revision 2
Program
Palisades Nuclear Plant - Raw Water Revision 0
Corrosion Report - Operational Cycle 14 and
1999 Refueling Outage
Palisades Nuclear Plant - Raw Water Revision 0
Corrosion Report - Operational Cycle 15 and
2001 Refueling Outage
GL 89-13 Generic Letter 89-13 - Service Water System
Problems Affecting Safety-Related Equipment
PPAC EPS162 Predetermined and Periodic Activity Control -
K-6A, Perform Selected Portions EPS-M-14
PPAC EPS038 Predetermined and Periodic Activity Control -
K-6A, Perform Selected Portions EPS-M-14
Condition Reports Reviewed to Assess Problem Identification Characterization
CAP032018 Inadequate Documentation of Heat Exchanger
Condition
CAP031990 Improper Flange Gaskets Installed
CAP031991 Tubes Blocked in E-22A (Emergency Diesel
Generator 1-1/K-6A Jacket Water Cooler)
CAP031992 Tube Blocked in E-31A (Emergency Diesel
Generator 1-1/K-6A Lube Oil Cooler)
CAP032048 Configuration of 1-1 Emergency Diesel
Generator Heat Exchanger E-22A End Plat
Gasket Differs From Intended Design
1R11 Licensed Operator Requalification
SPE-25 Simulator Performance Exam Revision 4
EI-1, Attachment 1 Site Emergency Plan Classification Revision 40
1R12 Maintenance Effectiveness
Critical Service Water Maintenance Rule Revision 2
Scoping Document and Associated Maintenance
Rule Performance Indicators
Critical Service Water System Health July 31, 2002
Assessments
EM - 20 Performance Monitoring Program Revision 9
EM - 25 Maintenance Rule Program Revision 4
Condition Reports Reviewed to Assess Maintenance Rule Evaluations
CPAL0201493 Vibration Data Indicates Early Stage Fault in the
New P-7CMotor Thrust Bearing
CPAL0201692 During Spare Motor Rebuild, Old Lower Radial
Bearing Shows Signs of Significant Thrust Loads
Miscellaneous Documents
EAR-2002-0027 CV-0873 is Prone To Binding in The Closed Revision 6
Position Due to SILT Deposition
Work Order Rebuild Service Water Pump P-7C Motor
24113994
Work Oder Rebuild Service Water Pump P-7A Motor
24810555
Condition Reports Reviewed to Assess Problem Identification Characterization
CPAL0201493 Vibration Data Indicates Early Stage Fault in the
New P-7CMotor Thrust Bearing
CPAL0002725 Service Water Pump P-7A Would Not Start From
Control Room
CAP031774 Maintenance Procedure Deficiency
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
Plant Procedures
Admin. 4.02 Administrative Procedure 4.02 - Control of Revision 18
Equipment
Miscellaneous Documents
Operators Risk Reports, Shift Supervisor Log October 15, 2002,
Entries, and Daily Work Schedules during outage through
on the Switchyard 345 KV F Bus concurrent October 18, 2002
with a planned outage on Component Cooling
Water Pump P-52C
Operators Risk Reports, Shift Supervisor Log October 20-25,
Entries, and Daily Work Schedules during outage 2002
on Emergency Diesel Generator 1-2
Operators Risk Reports, Shift Supervisor Log November 6-9, 2002
Entries, and Daily Work Schedules during outage
on Emergency Diesel Generator 1-1
Operators Risk Reports, Shift Supervisor Log November 14-15,
Entries, and Daily Work Schedules for planned 2002
maintenance on fuel oil transfer pumps
Operators Risk Reports, Shift Supervisor Log October 9, 2002;
Entries, and Daily Work Schedules for planned and October 10-11,
maintenance on High Pressure Safety Injection 2002
Control Valve 3059, and for emergent
maintenance on Door-16, Mechanical
Equipment Room
Operators Risk Report, Shift Supervisor Log November 26, 2002
Entries, and Daily Work Schedule during the
outage on switchyard 345 KV R Bus
Operators Risk Report, Shift Supervisor Log December 16-19,
Entries, and Daily Work Schedule during the 2002
component cooling water outage to spent fuel
pool cooling
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP032561 Small Amount of Seat Material Missing From
MV-CC184
CAP032569 Containment Sump Level Rises Unexpectedly
CAP032568 FI-0974, Vacuum Degasifier Pump Seal Water
Cooler E-67 Fails on Restoration of CCW
1R14 Non-Routine Plant Evolutions and Events
Plant Procedures
SFPO-3, Contingency Actions Revision 6
SOP 3, Section Standard Operating Procedure - Safety Injection Revision 49
7.5.11 and Shutdown Cooling System, To Fill Safety
Injection Tank and Outlet Piping Between the
Check Valves with HPSI Pumps
SOP 8, Main Turbine and Generating Systems Revision 57
2,
Step 1.4.4
Miscellaneous Documents
Primary Plant Computer data on spent fuel pool
temperature for October 25 - 28, 2002
213939 Work Order, Pressurizer pressure safety
injection channel circuit 4 power supply
213895 Work Order, Pressurizer vapor phase signal
converter
Control room log entries, November 11-13, 2002
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP032382 Shorted Conductor Causes Turbine Stop Valve
- 1 to Close Unexpectedly
CAP032379 #1 Stop Valve on Turbine Closes
1R15 Operability Evaluations
CPAL0201922 Found D/G Cooling Fan Damper D-28 (V-24C)
Resting on Critical Service Water Piping
CPAL0201632 Possible Wrong Coupling Installed on P-52A
CAP031434 Seismic Qualification of Turbine Building HP Air
X-tie to Safeguards Not Documented
CAP032041 Diesel Generator Turbo Charger Bolts Do Not
Meet Required Specifications
CAP031995 1/2" x 1 1/2" Bolt missing on Flange Which
Connects Turbocharger to Exhaust Pipe
Miscellaneous Documents
Work Request Replace Coupling Hub August 1, 2002
296114
FSAR Chapter 9.3 Component Cooling System Revision 23
1R16 Operator Workarounds
Plant Procedures
AP 4.12 Administrative Procedure - Operator Work- Revision 0
Around Program
Operator Work-Around / Challenge Identification and Disposition Forms
01-620C Energizing Preferred AC bus Y-30 and Y-40 from Revision 0
an inverter
01-200WA Redundant means of supplying fuel oil to the Revision 0
diesel generators during emergency conditions
01-010WA CCW containment isolation valves Revision 0
01-210WA Switchgear exhaust fan V-47 must be manually Revision 0
secured if Control Room Ventilation is in
emergency mode
01-680C FIC-0306 (SDC Flow Controller) does not have Revision 0
an automatic function
01-530C Temperature control valves for the CCW Heat Revision 0
Exchangers are under-sized to control CCW
temperatures during high temperature loading
conditions
01-590C Spent fuel transfer tube gate installation Revision 0
01-610C CCW Heat Exchangers (E-54A/B) are under Revision 0
sized
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP031928 Benchmarking Trip Reveals Gap in Operations
Performance of Aggregate Assessment Factor
CAP031931 Push Buttons Stick When Pushed on PIC
0101A/B
Condition Reports Reviewed to Assess Corrective Actions
CPAL9902017 Closure of Y30 Breaker #11 Caused Failure of
Inverter ED-08
CPAL990275 Inadvertent Actuation of Y30 Breaker 11
1R17 Permanent Plant Modifications
SOP 3, Standard Operating Procedure - Safety Injection Revision 49
Section 7.5.11 and Shutdown Cooling System, To Fill Safety
Injection Tank and Outlet Piping Between the
Check Valves with HPSI Pumps
SDR-02-1134 50.59 Screen, Safety Injection and Shutdown
Cooling System
IN 96-31 NRC Information Notice - Cross-Tied Safety
Injection Accumulators
M-203, Sheet 1 Piping and Instrument Diagram, Safety Injection, Revision 46
Containment Spray and Shutdown Cooling
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP032083 Procedure Revision to Fill Safety Injection Tank
T-82D Required Modification
1R19 Post Maintenance Testing
Plant Procedures
AP 5.19 Post Maintenance Testing Revision 11
EPS-M-15 Diesel Generator 1-2 - Refueling Frequency Revision 2
Maintenance
SOP-22 Emergency Diesel Generators Revision 33
MO-7A-2 Emergency Diesel Generator 1-2 Revision 54
EM-09-14 Attachment 1 - VT-2 Examination Checklist Revision 4
MO-7A-1 Emergency Diesel Generator 1-1 Revision 56
Work Orders
WO24113941 K-6B, Perform Selected Portions of EPS-M-15 October 21, 2002
WO24214020 Safety Injection Tank T-82D; Broken Weld on November 13, 2002
3/4" Line from Safety Injection Tank 12-inch
Discharge Piping to Manual Valve MV-ES3157
Which is Unisolable and associated FME Area
Material Control and Accountability Log
WO24211460 CK-DE 419, West Starting Air to K-6A Governor November 7, 2002
Check
WO24214010 EDG 1-1 Output Breaker 152-107 November 8, 2002
WO24212951 K-6A, Perform Selected Portions of EPS-M-14 November 7, 2002
WO24210690 Replace Valve MV-CC184, Valve Leaks By December 17, 2002
WO24210560 Replace Valve MV-CC923 December 18, 2002
WO24110645 Replace Valve MV-CC117, Will Not Fully Close December 20, 2002
Miscellaneous Documents
DBD-5.01 Design Basis Document - Diesel Engine and Revision 4
Auxiliary Systems
DBD-5.03 Design Basis Document - Emergency Diesel Revision 6
Generator Performance Criteria
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP031832 MO-7A-2, EDG 1-2 Monthly Surveillance Test
Acceptance Criteria Not Met
CAP031836 Acceptance Criteria Not Specified In Surveillance
Procedure MO-7A-2
CAP032047 Diesel Generator 1-1 Output Breaker Did Not
Close During Test Start
CAP032035 Gasket on 1-1 Diesel Generator Turbo Charger
Exhaust Appears to Be Broken/Leaking
CAP031801 Diesel 1-2 PT Drawer Left Open After Planned
Maintenance
CAP031799 Tech Spec Test MO-33 Aborted
CAP032418 Inconsistent Record Keeping for FME Areas
1R20 Refueling and Other Outage Activities
Plant Procedures
GOP-3 Mode 3 to Mode 2 Revision 17
GOP-4 Mode 2 to Mode 1 Revision 15
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP032329 Ineffective Communications Between PAL &
System Control Delayed Switching
CAP032366 Main Generator Frequency Meter Providing
Inaccurate Readings
1R22 Surveillance Testing
Completed Technical Specification Surveillance Tests
FT-2 Containment Building Post-Tension System Revision 11
QI-39 Auxiliary Feedwater Actuation System Logic Revision 0
Test, November 5, 2002
QO-1 Safety Injection System, November 15, 2002 Revision 47
DWO-13 Local Leak Rate Tests For Inner and Outer Revision 15
Personnel Air Lock Door Seals
RO-32 Containment Penetrations - Local Leak Rate Revision 9
Test
Miscellaneous Documents
FT-2 Technical Specification Surveillance Test Basis Revision 11
Document - Containment Building Post-Tension
System
NUREG-0820 Systematic Evaluation Plan October 1982
QO-1 Technical Specification Surveillance Test Basis Revision 3
Document - Safety Injection System
E-17, Sheet 4 Logic Diagram, Safety Injection Actuation Revision 16
Condition Reports Reviewed to Assess Corrective Actions
CPAL0202444 Procedure Step Inadvertently Deleted From `
Surveillance Test Section 6.0 Acceptance
Criteria
CPAL0103717 C Sensor Channel AFAS System Loss of
Power
CPAL0202691 FOGG B Module S/G Delta-P A< B Failure
CPAL9902698 AFAS/FOGG Panel +12 VDC Input Power
Supply Design Deficiency
CAP030948 Auto test function not operating on Auxiliary
Feedwater Actuation system
CPAL0202444 Procedure Step Inadvertently Deleted From
Surveillance Test Section 6.0 Acceptance
Criteria
1R23 Temporary Plant Modifications
Plant Procedures
SOP-1 Primary Coolant System Revision 50
ARP-5 Primary Coolant Pump Steam Generator and Revision 64
Rod Drives Scheme EK-09 (C-12)
AP-9.31 Temporary Modification Control Revision 19
AP-3.07 10 CFR 50.59 and 72.48 Reviews Revision13
E-609, sheet 23 Connection Diagram 125 VDC MCC D20 Unit Revision 5
- 23 DC Oil Lift Pump P-81B
E-184 Schematic Diagram Primary Coolant Pumps DC Revision 8
Oil Lift Pumps
WO 24212006 Install TM-2002-010 to Disconnect Test Solenoid June 15, 2002
for Moisture Separator Reheater Valve SV-0535
E-602, Sheet 2A Connection Diagram Turbine and Auxiliaries Revision 1
Terminal Boxes T22, T51, T52, T53, T54 & T60
E-121, Sheets Schematic Diagrams Turbine Control Revision 1
2-24
Temporary Modification Packages
TM 2002-015 Jumper to Allow DC Lift Pump P-81B to Operate August 6, 2002
Independent of the AC Oil Lift Pump Pressure
Switch due to DC Ground on the Circuit
TM-2002-010 Isolate Power to the Turbine Reheat and June 2, 2002
Intercept Valves due to Short to Ground on the
Neutral Wire of the Test Solenoid Valves
TM-2002-022 To Accept the Section of 345KV Transmission December 3, 2002
Line (North Line, Running between the Main
Power Transformer and the Switchyard) without
the Static Wire on Top of it.
Condition Reports Reviewed To Assess Problem Identification Characterization
C-PAL-0202321 Wiring to Solenoid Valve 0540, #2 Intercept June 14, 2002
Valve Found Swapped
C-PAL-0202320 Spurious Closures and Re-openings of CV-0540, June 14, 2002
- 2 Intercept Valve From Moisture Separator
Reheater E-9A to A Low Pressure Turbine
1E06 Emergency Plan Drill Evaluation
Plant Procedures
EI-1 Emergency Classifications and Actions Revision 40
EI-3 Communications and Notifications Revision 19
Miscellaneous Documents
Scope and Objectives, Fourth Quarter Drill December 11, 2002
Sequence of Events, Fourth Quarter Drill December 11, 2002
Completed event notification forms, plant December 11, 2002
message numbers 1 through 7
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP032440 PALEX Drill Critique Item: TSC to NRC
Communications Not Adequately Staffed
CAP032441 TSC Engineering Computer Configuration
CAP032442 Could Not Hear Drill Announcements - SE
Corner of Support Building, 2nd Floor
CAP032444 Emergency Drill Communications Within
Engineering and Maintenance
CAP032445 Wrong Procedure Revision in Simulator for
Emergency Planning Drill
CAP032446 RP Communication Between OSC and TSC Can
Be Improved
CAP032551 Equipment Issues During the Fourth Quarter EP
Training Drill
CAP032479 Van Buren County Used Outdated Emergency
Notification Forms During Drill
2OS3 Radiation Monitoring Instrumentation
RI-86B-9 Fuel Pool Area Monitor RIA-5709 Calibration Revision 4
RI-86G High Range Containment Monitor Calibration Revision 8
RR-9M Containment Atmosphere Gas Monitor RIA-1817 Revision 2
Calibration
Admin 1.16 Respiratory Protection Program Revision 0
HP 7.1 Health Physics Portable Instrumentation Revision 12
Program
HP 7.5 Self-Contained Breathing Apparatus (SCBA) Revision 4
Survivair Mark-2 Model 9842
HP 7.6 Inspection and Testing of the Survivair (SCBA) Revision 6
Breathing Air Cylinders
HP 9.13 Eberline Model RO-2/RO-2A and Model RO-20 Revision 9
Portable Ion Chambers
HP 9.15 Operation and Calibration of the Eberline Model Revision 9
6112 Teletector and Xetec Model 330A Telescan
HP 9.21 Ludlum Model 177 Ratemeter Revision 5
HP 9.45 Operational and Functional Checks of Health Revision 4
Physics Portable Instruments
HP 9.67 Operation and Calibration of the MGP Revision 10
Instruments CDM-21 Calibrator and DMC
Electronic Dosimeters
HP 9.77 Operation and Calibration of the Eberline Model Revision 11
AMS-4
RIA-I-9 Area Monitor Functional Check Revision 2
MI-6 Area Monitor Operational Check Revision 7
2002-33 Self-Assessment Report, Radiation Monitoring November 8, 2002
Instrument Program
2002-33 Self-Assessment Report, SCBA Maintenance November 8, 2002
and User Training
Self-Assessment Operation and Calibration of the MGP
Report, HP 9.67 Instruments CDM-21 Calibrator and DMC
Electronic Dosimeters
Certificate Of Eberline Model AMS-4, SN 120 October 24, 2002
Calibration
Certificate Of Eberline Model 6112 Teletector, CIN 66902 September 19, 2002
Calibration
Certificate Of PCM-1B, SN 21679 October 21, 2002
Calibration
Certificate Of Xetec Model 330A Telescan, CIN 45280 January 30, 2002
Calibration
Certificate Of Eberline Model RO-2, CIN 5222 October 21, 2002
Calibration
Database Printouts for Training, Medical Exams, November 20, 2002
and Fit Testings Records
Condition Reports
CPAL0103467 Frisker Failure Contributed to the Release of October 30, 2001
Contamination to a Clean Area
CPAL0200359 Failure of Workers Electronic Dosimeter to January 24, 2002
Record Dose in a High Radiation Area
CAP016520 Ion Chamber Reads Low by a Factor of Ten May 3, 2002
CAP030735 Radiation Safety Instrument Logsheet not November 30, 2002
Completed Consistently
Interim Compensatory Measures Order
Validation File
4OA1 Performance Indicator Verification
Reactor coolant system identified leak rate
performance indicator data submitted to the NRC
by licensee personnel for the first three quarters
of 2002
GOP-13, PCS Inventory Forms - calculated reactor Revision 15
coolant system leak rates completed daily for the
first three quarters of 2002
Condition Reports Reviewed To Assess Corrective Actions
CAP031806 Incorrect Data Reported on May 2002 NRC
Performance Indicator BI-02
4OA2 Identification and Resolution of Problems
Condition Reports Reviewed to Assess Corrective Actions
CIED0202545 TIA 2001-02 Prairie Island Non-Seismic Service July 7, 2002
Water Piping (Evaluation attached to
CAP 029041)
Condition Reports Reviewed to Assess Root Cause Evaluation and Corrective Actions
CAP032289 Automatic Reactor Trip and AFAS Actuation
Condition Reports Reviewed to Assess Condition Evaluation and Corrective Actions
CAP031618 Door 16 Mechanical Equipment Room Failure
Results in TS 3.7.10 A/B Entry
CAP031479 Door 16 Stuck Closed
CAP031099 Locked Inside Door 16 HVAC Area
CAP031121 Inability to Open Control Room HVAC Door 16
CAP031011 Mechanical Equipment Room Door 16 Failure
Condition Reports Reviewed to Assess Characterization of Identified Problems
CAP032576 Missed Opportunity to See Dog-Bone Failure
Coming for the Static Line
Miscellaneous Documents
FSAR Chapter 9.1 Service Water System Revision 23
TS 3.7.10 Technical Specification, Control Room
Ventilation Filtration
4OA3 Event Follow-up
Miscellaneous Documents
Post Event Review Report December 1, 2002
EN#39414 Emergency Notification To Regulatory Agencies, December 2, 2002
CFR 50.72, 4-hour Non-Emergency Report,
for reactor protection system actuation
LCO 3.8.1 Technical Specification Limiting Condition For Amendment 189
Operation, AC Sources Operating
LCO 3.4.5 Technical Specification Limiting Condition For Amendment 189
Operation, PCS Loops Mode 3
EOP-1 Emergency Operating Procedure-1, Standard Revision 12
Post Trip Actions
EOP-8 Emergency Operating Procedure-8, Loss of Revision 13
Offsite Power/Forced Circulation Recovery
SOER 99-1 Significant Operating Experience Report, Loss of December 27, 1999
Grid
Condition Reports Reviewed To Assess Characterization of Identified Problems
CAP032289 Automatic Reactor Trip and AFAS Actuation
CAP032270 During R Bus Restoration, Open Indicator on
2-302 Failed To Light
CAP032272 Dual Indication of MOD-24R2 Disconnect During
Restoration of R Bus
CAP032273 27R4 Kirk Key Locking Wheel Broke
CAP032293 CV-0782, Steam Generator E-50A Atmospheric
Steam Dump Valve Failed To Indicate Closed
CAP032291 Pressurizer Spray Valve CV-1057 Did Not Close
During Plant Transient
CAP032294 Control Rod Drive Mechanism #20 Low Limit
Light Did Not Illuminate as Expected
CAP032296 High Pressure Seal Oil Backup Pump 24 Did Not
Auto Start
CAP032299 RV-2006 Lifted Several Times Due To Sluggish
Backpressure Regulator Control
CAP032312 POS-780 Indicates Improperly
CAP032350 On-shift C&RP Personnel Not Informed of Plant
Shutdown
4OA5 Other
Miscellaneous Documents
Request For Enforcement Discretion - Safety November 13, 2002
Injection Tanks
Unplanned Plant Derate / LCO or Forced Outage November 12, 2002
Response Action Item List
LCO 3.5.1 Technical Specification Limiting Condition for Amendment 191
Operation 3.5.1, Safety Injection Tanks and
associated basis
Notice of Enforcement Discretion for Nuclear November 15, 2002
Management Company LLC Regarding
Palisades (NOED 02-3-059)
EOP Validation Form for EOP Supplement 31, June 11, 2002
Supply AFW Pumps From Alternate Sources
EA-PSA-Tornado- Engineering Analysis, Potential Core Damage June 21, 2002
2-07 Impact Due to a Tornado
EA-SGK-02-001 Engineering Analysis, Evaluation of the Impact June 21, 2002
of a Loss of Condensate Storage Tank on the
Auxiliary Feedwater Pumps
Condition Reports Reviewed To Assess Problem Identification Characterization
CAP032088 Violation of Technical Specification 3.5.1.B,
Safety Injection Tanks
CAP032066 T-82D Safety Injection Tank Lowering Level
Trend
CAP032073 T-82D, SIT, Level Instrument Line Leak
CAP032074 Leakage Documented in CAP032073 Has
Contacted Other Plant Components
Condition Reports Reviewed To Assess Corrective Actions
CPAL0201930 Impact to Performance Time Limit Not Validated
in Emergency Operating Procedure Revision
Condition Report Reviewed To Assess Root Cause Evaluation
CAP032073 T-82D, Level Instrument Line Leak
2