IR 05000255/2003002

IR 05000255-03-002, on 12/29/2002 - 03/31/2003, Nuclear Management Company, LLC

ML031190768
Person / Time
Site:	Palisades
Issue date:	04/29/2003
From:	Eric Duncan NRC/RGN-III/DRP/RPB6
To:	Cooper D Nuclear Management Co
References
IR-03-002
Download: ML031190768 (55)

Text

April 29, 2003

SUBJECT:

PALISADES NUCLEAR GENERATING PLANT NRC INTEGRATED INSPECTION REPORT 50-255/03-02

Dear Mr. Cooper:

On March 31, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palisades Nuclear Generating Plant. The enclosed report documents the inspection findings which were discussed on April 11, 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, three findings of very low safety significance (Green)

were identified which involved violations of NRC requirements. However, because of their 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 NRCs Enforcement Policy.

If you contest 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/

Eric Duncan, Chief Branch 6 Division of Reactor Projects Docket No. 50-255 License No. DPR-20

Enclosure:

Inspection Report 50-255/03-02 See Attached Distribution

DOCUMENT NAME: C:\\MyFiles\\Copies\\Karen\\ML031190768.wpd To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy OFFICE RIII NAME EDuncan:dtp DATE 04/29/03 OFFICIAL RECORD COPY

REGION III==

Docket No:

50-255 License No:

DPR-20 Report No:

50-255/03-02(DRP)

Licensee:

Nuclear Management Company, LLC Facility:

Palisades Nuclear Generating Plant Location:

27780 Blue Star Memorial Highway Covert, MI 49043-9530 Dates:

December 29, 2002, through March 31, 2003 Inspectors:

J. Lennartz, Senior Resident Inspector R. Krsek, Resident Inspector R. Alexander, Radiation Specialist T. Madeda, Physical Security Inspector, RIII C. Phillips, Senior Operations Engineer, RIII Approved by:

Eric Duncan Branch 6 Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000255/03-02; Nuclear Management Company, LLC; 12/29/2002 - 03/31/2003; Palisades

Nuclear Generating Plant; Equipment Alignment; Surveillance Testing; Event Followup.

This report covers a 3-month period of baseline resident inspections, a physical protection inspection, and a radiation protection inspection. The inspections were conducted by resident inspectors and 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 and Self-Revealing Findings

Cornerstone: Mitigating Systems

C

Green.

The inspectors identified a finding for the failure to implement adequate corrective actions to prevent recurrence of issues associated with the construction of seismic scaffolding near safety-related systems.

This finding was more than minor because if left uncorrected it would become a more significant safety concern in that inadequately constructed scaffold could affect the availability of mitigating systems during a seismic event. The finding was of very low safety significance because the finding did not screen as potentially risk significant due to a seismic initiating event and did not involve the total loss of any safety function that contributes to core damage accident sequences initiated by seismic events. The inspectors also determined that this finding represented continued human performance deficiencies in the construction of seismic scaffolding near safety-related systems. A Non-Cited Violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified. (Section 1R04.1)

Cornerstone: Barrier Integrity

C

Green.

The inspectors identified a finding for the failure to ensure that testing of the fuel handling area ventilation system was performed in accordance with test procedures which incorporated the appropriate requirements and acceptance limits specified in Technical Specification 5.5.10, Ventilation Filter Testing Program.

This finding was more than minor because if left uncorrected it would become a more significant safety concern in that the radiological barrier function provided by the fuel handling area ventilation system was degraded and was not being tested adequately. The finding was of very low safety significance because the finding represented a degradation of only the radiological barrier function provided for the spent fuel pool. The inspectors also determined that this finding was a result of human performance deficiencies related to developing and implementing the Technical Specification surveillance. A Non-Cited Violation of 10 CFR 50, Appendix B, Criterion XI, Test Control, was identified.

(Section 1R22.1)

C

Green.

The inspectors determined that a self-revealed finding was associated with the failure to restore an inoperable channel of containment hydrogen monitoring within the allowed outage times specified in Technical Specification Action Statements 3.3.7.A and 3.3.7.D.

The finding was more than minor because the barrier integrity cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events was affected. The finding was determined to be of very low safety significance after a Region III Senior Reactor Analyst, in conjunction with the inspectors, performed a SDP Phase 3 assessment. Utilizing NUREG-1675, Basis Document for Large Early Release Frequency Significance Determination Process, the analyst determined that the significance threshold for large early release frequency of 100 volume percent per day leak rate from containment would not be exceeded.

The inspectors also noted that this finding was attributable to a latent human performance deficiency which occurred during the April 2001 refueling outage, but was self-revealed in December 2002. A Non-Cited Violation of Technical Specification Section 3.3.7 was identified. (Section 4OA3.1)

B.

Licensee Identified Findings One violation of very low safety significance, which was identified by the licensee was reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. The violation and corrective action tracking numbers are listed in Section 4OA7 of this report.

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 During an Unusual Event for an unexplained lowering level in the service water pump bays on February 16, 2003, operators reduced power to 89 percent to stabilize the balance of plant equipment. The lowering level in the service water pump bays was subsequently determined to have been caused by ice forming on the intake structure in Lake Michigan which reduced flow to the pump bays. On February 21, 2003, power was again raised to full power after licensee personnel determined that no ice remained and that no major damage had occurred to the intake structure.

C On March 16, 2003, the plant was shut down to begin a scheduled refueling outage which was ongoing when the inspection period ended.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

==1R04 Equipment Alignment

==

.1 Inadequate Corrective Actions for Seismic Scaffolding Built Near Safety-Related

Equipment (71111.04S)

a. Inspection Scope

During walkdowns of the auxiliary feedwater system, the inspectors assessed the condition of seismic scaffolding built near safety-related equipment. The inspectors verified the scaffolds were built in accordance with the licensees procedures and reviewed the licensees corrective actions taken for scaffolding issues previously identified by the NRC.

b. Findings

Introduction The inspectors identified a finding of very low safety significance (Green) that is being treated as a Non-Cited Violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, for the failure to implement adequate corrective actions to prevent recurrence for issues associated with the construction of seismic scaffolding near safety-related systems.

Description On February 27, 2003, the inspectors identified that scaffolding erected near safety-related equipment in the west engineering safeguards room did not meet the minimum spacing requirements from the safety-related backup suction piping to Auxiliary Feedwater Pump P-8C. The inspectors also noted that the scaffolding did not have the required engineering evaluation and approval to be built in this manner. Step 5.5.3a of Procedure MSM-M-43, Scaffolding, required, in part, that a minimum separation of 1-inch in all directions shall be maintained between braced scaffolding and safety-related equipment. Step 5.5.7 of Procedure MSM-M-43 required, in part, that design engineering provide justification and approval for deviating from the procedure requirements.

The licensee rebuilt the scaffold and initiated Condition Report CAP033667, Seismic Scaffold Does Not Meet Installed Plant Equipment Separation Requirement. The licensees immediate corrective actions included a temporary suspension of scaffold erection activities, stand-down and retraining of scaffold builders and supervisors, and an extent of condition walkdown to identify other potentially deficient scaffold installations. During the extent of condition walkdown, the licensee identified and corrected several additional seismic scaffolds which were not built in accordance with Procedure MSM-M-43.

On March 3, 2003, the inspectors again identified additional seismic scaffolding erected near safety-related equipment in the component cooling water heat exchanger room which did not meet the requirements of Procedure MSM-M-43. The licensee rebuilt the scaffold, initiated a Condition Report, and again took additional immediate corrective actions.

The inspectors reviewed NRC-identified scaffold control issues which had occurred in the past 2 years to determine if there had been prior opportunities to address seismic scaffolding construction deficiencies. In February and March 2001, just prior to the start of the 2001 Refueling Outage, the NRC issued a Green finding and associated Non-Cited Violation (NCV) 50-255/01-06-02, for several examples of the licensees failure to adequately implement procedural requirements for the control of seismic scaffolding in the vicinity of safety-related equipment. The licensees root cause analysis for this condition adverse to quality determined that the site lacked a programmatic method to control scaffold design, erection, inspection and approval. The licensee completed all corrective actions to prevent recurrence for this finding on October 15, 2002.

On December 17, 2002, the NRC documented a Green finding and associated NCV 50-255/02-10-01, for several examples of the licensees failure to adequately implement procedural requirements for the control of seismic scaffolding in the vicinity of safety-related equipment. Based on the identification of repetitive failures in the past 2 years to adequately control seismic scaffolding construction the inspectors concluded that previous remedial and corrective actions to prevent recurrence were not effective.

The inspectors determined that the failure to implement adequate corrective actions to prevent recurrence of issues associated with the construction of seismic scaffolding near safety-related systems was a licensee performance deficiency warranting a significance evaluation.

Analysis The inspectors determined that this finding was greater than minor in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on February 21, 2003, in that the finding would become a more significant safety concern if left uncorrected.

Specifically, scaffolding installed in the vicinity of safety-related equipment could fail during a seismic event and result in damage to mitigating equipment. Consequently, continued human performance deficiencies in the construction of scaffolding near safety-related systems could affect the availability of mitigating systems that respond during seismic events, and if left uncorrected would become a more significant safety concern.

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, and determined that the finding:

• was not a design or qualification deficiency;

• did not represent an actual loss of safety function of a system;

• did not represent an actual loss of a safety function of a single train for greater than Technical Specification outage time;

• did not represent an actual loss of a safety function of one or more Non-Technical Specification trains of equipment;

• did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event; C

did not involve the total loss of any safety function that contributed to core damage accident sequences initiated by seismic events; and C

did not involve the loss or degradation of equipment or function designed to mitigate a seismic initiating event.

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 in the case of significant conditions adverse to quality, measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to this, the licensees corrective actions to preclude repetitive human performance deficiencies during the construction of seismic scaffolding near safety-related systems have not been effective as evidenced by the following:

• NCV 50-255/01-06-02 issued on April 19, 2001, for several examples of the failure to adequately implement procedural requirements for the control of seismic scaffolding in the vicinity of safety-related equipment;

• NCV 50-255/02-10-01 issued on December 17, 2002, for the failure to adequately implement procedural requirements for the control of scaffolding in the vicinity of safety-related equipment; and

• continued examples of the failure to adequately implement requirements for the construction of seismic scaffolding near safety-related equipment in February and March 2003.

This violation is associated with an inspector identified 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, Corrective Action, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 50-255/03-02-01)

This issue was entered in the licensees corrective action program as Condition Reports CAP033667, Seismic Scaffold Does Not Meet Installed Plant Equipment Separation Requirement, and CAP033744, Seismic Scaffold That Did Not Appear to Meet Equipment Separation Requirement.

.2 Semiannual Equipment Alignment Walkdowns

a. Inspection Scope

The inspectors walked down the Auxiliary Feedwater System utilizing piping and instrumentation diagrams, system operating procedures and system checklists to verify that accessible system components were correctly aligned. The inspectors also reviewed active maintenance work requests; active design and engineering issues, including known operator workarounds and temporary modifications; to verify that the equipments safety function was not adversely impacted.

b. Findings

No findings of significance were identified.

.3 Quarterly Equipment Alignment Walkdowns

a. Inspection Scope

The inspectors performed partial equipment alignment walkdowns on the following three systems:

C Emergency Diesel Generator 1-2; C

Service Water Traveling Screen Back Wash and Warm Water Recirculation Systems; and C

Low Pressure Safety Injection Pump P-67A.

The inspectors walked down the Emergency Diesel Generator and Low Pressure Safety Injection Pump P-67A to verify proper system lineup while redundant plant equipment was out of service. After the Unusual Event that was declared on February 16, 2003, for the problems associated with the service water intake crib the inspectors walked down the Service Water Traveling Screen Systems. 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.

Further, the inspectors reviewed condition reports related to equipment alignment issues to verify that the problems were appropriately characterized, and that planned and completed corrective actions were reasonable.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors toured the following six areas in which a fire could affect safety-related equipment:

• Component Cooling Water Room (Fire Area 16);

• Control Room Complex (Fire Area 1);

• Intake Structure (Fire Area 9);

• Emergency Diesel Generator 1-2 Fuel Oil Day Tank (Fire Area 8);

• Engineered Safeguards Panel Area (Fire Area 15); and

• Containment (Fire Area 14).

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 that the sprinkler fire suppression system, smoke detection system, and manual fire fighting equipment for these areas were available.

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 Updated 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.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors observed heat exchanger performance testing for the following heat exchangers:

• Component Cooling Water Heat Exchanger E-54B; and

• Containment Air Cooler VHX-3.

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 annual operating requalification examinations on January 24, 2003. The inspectors observed portions of operator performance during job performance measures in the simulator for one Senior Reactor Operator and three Reactor Operators. The inspectors assessed the licensed operators ability to complete the following tasks:

C fill a safety injection tank; C

alternate pressurizer pressure controls; and C

start and load an emergency diesel generator.

The inspectors verified that the operators were able to complete the tasks in accordance with applicable plant procedures and that the success criteria as established in the job performance measures were satisfied.

The inspectors observed the licensee evaluators to ensure that no inappropriate cues were provided by the evaluators while the licensed operators were completing the tasks.

The inspectors also reviewed the documented operator evaluations to assess the licensee evaluators ability to identify licensed operator performance weaknesses.

In addition, the inspectors verified that condition reports written regarding licensed operator requalification training were entered into the licensees corrective action program with the appropriate significance characterization.

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 six activities were reviewed:

C Planned maintenance on Control Room Heating, Ventilation and Air Conditioning Charcoal Filter Testing (RT-85), Steam Generator Pressure Instrumentation Calibrations (RI-5), and West Engineered Safeguards Room Cooler Fan testing during the week of January 6, 2003; C

Planned outage on Switchyard 345 Kilovolt (KV) Rear-Bus, Emergency Diesel Generator 1-1 Testing, and Traveling Screen F-4C during the week of February 2, 2003; C

Planned troubleshooting on the Auxiliary Feedwater Actuation System Automatic Test Circuitry on February 11, 2003; C

Scheduled maintenance activities from February 16-19, 2003, during the Unusual Event for frazil ice on the intake crib which caused reduced flow from the ultimate heat sink; C

Scheduled maintenance activities on March 18, 2003, during the declared Alert due to a fire in the protected area which resulted in the loss of all charging pumps and on March 19-23, 2003, during the first primary coolant system reduced inventory period in the scheduled refueling outage; and C

Scheduled maintenance activities on March 25-27, 2003, during the declared Alert due to a loss of offsite power.

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

.1 Operator Response to Unexplained Lowering Level In Service Water Bay

a. Inspection Scope

The inspectors observed operator performance during an unexplained lowering level in the service water bay on February 16, 2003. This event occurred while the plant was at full power and the inspectors responded to the site after licensee personnel declared an Unusual Event. The inspectors assessed the operators response to verify that procedural guidance contained in the Alarm Response, Off-Normal, System Operating and General Operating Procedures was appropriate and adhered to during this event.

The inspectors also reviewed the control room logs and event notifications to the local and state municipalities on the declared Unusual Event to verify the event was accurately described. In addition, the inspectors reviewed the resultant condition reports which were initiated to verify that these issues were entered into the corrective action program with the appropriate characterization and significance.

Licensee personnel subsequently determined that the lowering level in the service water bay was due to frazil ice buildup on the intake crib. This issue is discussed further in Section 4OA3.4 of this report.

b. Findings

No findings of significance were identified.

.2 Operator Response to Loss of All Charging Pumps

a. Inspection Scope

The inspectors reviewed actions taken by the control room operators in response to the unexpected loss of all charging pumps during solid plant operations on March 18, 2003, while the plant was in Mode 5, Cold Shutdown. The inspectors assessed the operators response to determine if the actions taken were as required by plant procedures and to determine if any human performance deficiencies contributed to the unplanned event. This issue resulted in a declared Alert on March 18, 2003, which is discussed further in Section 4OA3.5 of this report.

b. Findings

The loss of all charging pumps event was the subject of an NRC special inspection and any findings related to operator performance during the event will be documented in Inspection Report 50-255/03-05(DRP).

.3 Operator Response to Loss of Offsite Power With Resultant Loss of Shutdown Cooling

a. Inspection Scope

The inspectors observed the control room operators response following the unexpected loss of offsite power which resulted in the loss of shutdown cooling on March 25, 2003.

The inspectors verified that control room operators actively used and accurately implemented Off-Normal Procedure 17, Loss of Shutdown Cooling, and Off-Normal Procedure 2.1, Loss of AC [Alternating Current] Power, as required to restore the shutdown cooling system and mitigate the event in a timely manner. The inspectors assessed the operators response to determine if any human performance deficiencies contributed to the unplanned event. This issue resulted in a declared Alert on March 25, 2003, which is discussed further in Section 4OA3.6 of this report.

b. Findings

The loss of offsite power event was the subject of an NRC special inspection and any findings regarding operator performance while responding to the event will be documented in Inspector Report 50-255/03-05(DRP).

.4 Restoration of Offsite Power Sources to Safety-Related Busses

a. Inspection Scope

On March 27, 2003, the inspectors observed the control room operators during a planned evolution to align offsite power to the safety-related 2400 Volt Busses 1C and 1D and then unload and secure the emergency diesel generators. The planned evolution was performed after offsite power to the startup transformers was restored following the loss of all offsite power event that occurred on March 25, 2003. The inspectors verified that control room operators actively used and accurately implemented Standard Operating Procedure 22, Emergency Diesel Generators, and Off-Normal Procedure 2.1, Loss of AC Power, as required.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed five operability assessments as documented in the associated condition reports for the following risk significant plant equipment and analyses:

• Service Water System;

• Diesel Generator 1-2 Room Ventilation Dampers;

• Computer Code Errors Discovered in the Accident Analysis;

• Component Cooling Water System; and

• Component Cooling Water Heat Exchanger Service Water Outlet Control Valve CV-0826.

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, Updated 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.

The inspectors reviewed select condition reports to verify that identified problems regarding operability evaluations were entered into the licensees corrective action program with the appropriate significance characterization. The inspectors also verified that identified corrective actions were reasonable and had been implemented in a manner commensurate with safety.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed the engineering analyses, safety analyses, modification documents and design change information associated with the following permanent modification to the Low Pressure Safety Injection Pump P-67B:

• Install Casing Vent Valves on Low Pressure Safety Injection Pumps P-67A and P-67B.

The inspectors discussed the modifications with the appropriate licensee personnel. In addition, the inspectors reviewed the applicable sections of the Updated Final Safety Analysis Report to verify that the modifications would not adversely impact the systems safety functions.

Further, the inspectors reviewed condition reports associated with installation of the modification to verify that identified problems associated with the modifications were appropriately characterized and entered into the licensees corrective action program.

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 five post maintenance test activities were reviewed:

C High Pressure Safety injection Pump P-66A; C

Emergency Diesel Generator 1-2; C

Reactor Protection System and Auxiliary Feedwater Actuation System Setpoint Adjustments; C

Service Water Bay Low Level Alarm Setpoint Change; and C

Low Pressure Safety Injection Pump P-67B.

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

.1 Review of Outage Plan and Monitoring Of Shutdown Activities

a. Inspection Scope

The inspectors reviewed the results from the Probabilistic Safety Assessment Groups review of the 2003 refueling outage schedule and various 3-day and 2-week look ahead assessments. The assessments were conducted to verify that plant equipment required by General Operating Procedure (GOP) 14, Shutdown Cooling Operations was not adversely impacted by the scheduled activities, and that plant risk was appropriately considered and minimized during the scheduled outage activities. The inspectors reviewed the licensees responses to Generic Letter (GL) 88-17, Loss of Decay Heat Removal, and plant procedures to verify that previous commitments were in place and adequately addressed the recommendations referenced in GL 88-17.

The inspectors observed portions of the plant shutdown and subsequent cooldown at the start of the refueling outage to verify that the evolutions were completed in accordance with plant procedures. The inspectors also reviewed primary coolant system temperature data to verify that Technical Specification plant cooldown limits were adhered to and condition reports to verify that identified problems were entered into the licensees corrective action program with the appropriate significance characterization.

b. Findings

No findings of significance were identified.

.2 Licensee Control Of Outage Activities

a. Inspection Scope

The inspectors assessed the following aspects of the licensees outage activities:

C Equipment Configuration Management: The inspectors verified that equipment designated in GOP-14, Shutdown Cooling Operations, was maintained available as required to minimize plant risk; C

Reactor Coolant System Temperature and Level Instrumentation: The inspectors verified that reactor coolant system temperature, level and pressure indication were available and actively being used to accurately monitor plant conditions; C

Electrical Power Availability: The inspectors verified that the configuration of the electrical system was maintained to ensure equipment necessary to minimize plant risk remained operable; C

Decay Heat Removal System Monitoring: The inspectors monitored Shutdown Cooling System parameters to verify the system was operating properly; C

Spent Fuel Pool Cooling System Operation: The inspectors verified that methods to recover spent fuel pool cooling and inventory existed and that equipment necessary for cooling was available and not adversely affected by ongoing outage activities; C

Reactor Coolant System Inventory Control: The inspectors verified that plant equipment needed for primary coolant system inventory control was appropriately maintained during periods of higher risk such as during mid-loop operations; and C

Reactivity Control: The inspectors verified that the licensee identified and implemented the appropriate administrative controls on potential boron dilution paths.

b. Findings

No findings of significance were identified.

.3 Reduced Inventory and Mid-Loop Conditions

a. Inspection Scope

The inspectors observed the control room operators during the primary coolant system drain down to reduced inventory to verify that the operators maintained positive control of the primary coolant system level. The inspectors also verified that the configuration of plant equipment was in accordance with GOP 14, Shutdown Cooling Operations, during reduced inventory and mid-loop primary coolant system conditions. In addition, the inspectors verified that the licensees procedures were appropriate and implemented as prescribed for the following activities:

C Containment closure capability was in place for the mitigation of radioactive releases, which included appropriate staging of personnel and equipment, and current lists available in the control room of inoperable containment penetrations and of cables through the equipment hatch; C

At least two independent, continuous indications of primary coolant system temperature and level were available; and C

At least two additional means of adding inventory to the primary coolant system were available, in addition to the residual heat removal system.

The inspectors also verified that Off-Normal Procedures were available which addressed reduced inventory operation and that contingency plans existed to re-power vital electrical busses if the primary source of electrical power was lost.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

.1 Fuel Handling Ventilation System Testing

a. Inspection Scope

The inspectors observed portions of the Fuel Handling Ventilation System testing to verify that the testing was conducted in accordance with prescribed procedures.

The inspectors reviewed the licensee and vendor test procedures to verify that testing was done in accordance with Regulatory Guide 1.52, Revision 2 and the American Society of Mechanical Engineers (ASME) Standard N-510-1989 as required by Technical Specifications. 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 Updated 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 the fuel handling ventilation surveillance testing activities to verify that conditions adverse to quality were appropriately entered into the licensees corrective action program and that identified corrective actions were reasonable and had been implemented in a manner commensurate with significance.

b. Findings

Introduction The inspectors identified a Green finding that is being treated as a Non-Cited Violation of 10 CFR 50, Appendix B, Criterion XI, Test Control, for the failure to ensure that testing of the fuel handling area ventilation system was performed in accordance with test procedures which incorporated the appropriate requirements and acceptance limits specified in Technical Specification 5.5.10, Ventilation Filter Testing Program.

Description The inspectors reviewed and observed the licensee perform Procedure RT-85C, Technical Specification Surveillance Procedure - Fuel Handling Area Ventilation System Filter Testing, on March 3, 2003. The purpose of the surveillance test was to demonstrate operability of the Fuel Handling Ventilation System in accordance with the Surveillance Requirements of Technical Specification 3.7.12, Fuel Handling Area Ventilation System, and the Ventilation Filter Testing Program specified in Section 5.5.10 of the Technical Specifications. The inspectors noted that the surveillance test was performed with the use of licensee system engineers concurrent with a contractor and contractor specific procedures for certain portions of the test.

The inspectors identified numerous issues associated with the testing of the Fuel Handling Ventilation System which included:

(1) human performance issues by the licensee and contractor personnel associated with performing the test in accordance with the test procedures;

(2) test procedures which did not incorporate all the requirements and acceptance limits contained in Regulatory Guide 1.52, Revision 2 and the ASME Standard N-510-1989, as required;

(3) lack of contractor oversight by licensee personnel during portions of the test to assure that the testing was performed as required; and

(4) inadequate material condition of specific portions of the Fuel Handling Ventilation System. Consequently, the inspectors concluded that the surveillances performed on the fuel handling ventilation system were inadequate. Some specific issues the inspectors identified included the following:

C Several instances where procedure steps were not implemented as prescribed and were performed out of sequence for the Continuous Use procedures; C

Sampling of the filter testing challenge gas downstream of the charcoal and high efficiency particulate air (HEPA) filters was performed in a manner that air outside the filter housings diluted the downstream filter test results; C

Upon completion of the required visual inspection of the Fuel Handling Ventilation System by the licensee and contractor as satisfactory with minor exceptions, the inspectors identified the following issues:

- a previously unidentified through-wall tear on the expansion joint for the suction of Ventilation Fan V-8B;

- a tear and hole on the east side of the exhaust ductwork from Ventilation Fan V-8B; and

- a hole on the southwest corner of the exhaust ductwork from Ventilation Fan V-8B.

The holes and tears identified by the inspectors constituted bypass paths around the Fuel Handling Ventilation System to the atmosphere.

C Contractors procedure utilized to perform the HEPA and charcoal filter efficiency tests was written to ASME Standard N-510-1975 as opposed to ASME Standard N-510-1989 which was required by Technical Specifications; and C

No evidence that an air-aerosol mixing uniformity test had been performed as required by ASME Standard N-510-1989 as a prerequisite for performing HEPA and charcoal filter efficiency tests. In addition, licensee personnel could not identify an exemption from the Office of Nuclear Reactor Regulation for not having to perform the test.

Licensee personnel subsequently initiated condition reports for the inspector identified issues which were entered into the licensees corrective action program. In addition, condition reports were generated for additional deficiencies that were identified by licensee personnel who reviewed the circumstances surrounding the inspector identified issues associated with this testing. As a result, licensee personnel subsequently revised the test procedures and re-performed the tests, including the air-aerosol mixing uniformity test, to demonstrate that the Fuel Handling Ventilation System was operable for refueling operations.

The inspectors determined that the failure to ensure that testing was performed for the Fuel Handling Ventilation System in accordance with written test procedures which incorporated the applicable requirements and acceptance limits 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 February 21, 2003, because the finding affected the barrier integrity cornerstone and if left uncorrected would become a more significant safety concern.

Specifically, human performance deficiencies identified by the inspectors resulted in the failure to ensure that the fuel handling area ventilation system testing was performed in accordance with test procedures which incorporated the appropriate requirements and acceptance limits. Consequently, the radiological barrier function provided by the fuel handling area ventilation system was degraded and was not being tested adequately, and if left uncorrected would become a more significant safety concern.

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 although the barrier integrity cornerstone was adversely impacted, the finding represented a degradation of only the radiological barrier function provided for the spent fuel pool.

Therefore, the finding was determined to be of very low safety significance (Green).

Enforcement 10 CFR 50, Appendix B, Criterion XI, Test Control, requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Contrary to this, on March 3, 2003, the licensee failed to assure that testing was performed in accordance with the written test procedures for the Fuel Handling Ventilation System. In addition, the licensee failed to assure that the written test procedures incorporated the requirements and acceptance limits as required by Technical Specification 5.5.10, Ventilation Filter Testing Program.

This violation is associated with an inspector identified 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 XI, Test Control, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV50-255/03-02-02)

This issue was entered in the licensees corrective action program as Condition Reports CAP033742, CAP033749, CAP033764, CAP033788, CAP033829, CAP033895, CAP033907, and CAP033910.

.2 Other Routine Surveillance Tests

a. Inspection Scope

The inspectors reviewed seven surveillance testing activities conducted on the following risk-significant plant equipment:

C Emergency Diesel Generator 1-1; C

Reactor Protection System Steam Generator Pressure Channel D Calibration; C

Reactor Protection System Pressurizer Pressure Channel D Calibration; C

Emergency Air Lock Local Leak Rate Test; C

Auxiliary Feedwater Actuation System; C

Control Room Heating, Ventilation and Air Conditioning System; and C

Safety Injection Tank Outlet Check Valve.

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 Updated 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 identified problems were entered into the corrective action program with the appropriate significance characterization and 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 documentation and associated 10 CFR 50.59 evaluation for the following temporary plant modification:

• 2003-003, Steam Generator Narrow Range Level Setpoint Changes.

The inspectors verified that the temporary modification did not adversely impact other safety-related equipment and that the modification was being controlled in accordance with Administrative Procedure 9.31, Temporary Modification Control, requirements.

In addition, the inspectors reviewed selected condition reports regarding temporary modifications 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, Radiological Boundary Verification, and Radiation Work Permit (RWP)

Reviews

a. Inspection Scope

The inspectors reviewed the stations implementation of physical and administrative controls over access to radiologically restricted areas (RRAs), including worker adherence to these controls, by reviewing station procedures, RWPs, electronic dosimetry alarm set points, and walking down radiologically significant areas (radiation areas, high radiation areas (HRAs), and locked HRAs) of the station. Specifically, areas in the Reactor Building and the Auxiliary Building were observed to verify these areas were posted and controlled in accordance with 10 CFR Part 20, licensee procedures, and Technical Specifications.

Additionally, the inspectors reviewed the licensees assessment of an airborne radioactivity area created around the containment cavity after flood-up, which had the potential to result in doses greater than 50 millirem committed effective dose equivalent, to evaluate the effectiveness of engineering controls (High-Efficiency Particulate Air (HEPA) ventilation units) and respiratory protection used to mitigate worker internal dose.

b. Findings

No findings of significance were identified.

.2 High Risk Significant, High Dose Rate (HDR)-Locked HRA and Very HRA Controls

a. Inspection Scope

The inspectors reviewed the stations implementation of physical and administrative controls over access to HDR-locked HRAs and Very HRAs, including a discussion of these controls with Radiation Protection (RP) supervisors and lead RP technicians, to verify that processes and procedures (including any recent changes) implementing these controls provided an appropriate level of worker protection. The inspectors conducted walkdowns of all accessible HDR-locked HRA boundaries to verify adequate posting and control of all entrances into these areas. Additionally, the inspectors reviewed selected plant survey maps to confirm that no Very HRAs existed in the current plant configuration as discussed with the RP staff.

b. Findings

No findings of significance were identified.

.3 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed Condition Reports (CRs) completed in conjunction with the refueling outage which focused on access control to radiologically significant areas, radiation worker practices, and RP technician practices. The inspectors reviewed these documents to assess the licensees ability to identify repetitive problems, contributing causes, the extent of conditions, and implement corrective actions intended to achieve lasting results.

Additionally, the inspectors reviewed the licensees root cause evaluation related to a November 2002 event in which two workers received unintended occupational exposures of 134 millirem and 174 millirem, respectively, following an at-power containment entry to repair a defective weld. The licensee reported the event as an Occupational Radiation Safety Performance Indicator Unintended Exposure Occurrence in the 4th Quarter 2002 and the inspectors reviewed the evaluation to determine if there was an overexposure or substantial potential for an overexposure related to the event.

b. Findings

No findings of significance were identified.

2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls (71121.02)

.1 Radiological Work/ALARA Planning

a. Inspection Scope

The inspectors reviewed the stations procedures for radiological work/ALARA planning and scheduling, and evaluated the dose projection methodologies and practices implemented for the refueling outage, to verify that sound technical bases for outage dose estimates existed. Specifically, the inspector reviewed six radiologically significant Radiation Work Permit (RWP)/ALARA planning packages to verify that adequate person-hour estimates, job history files, lessons learned, industry experiences, and the use of mockups (where applicable) were utilized in the ALARA planning process and to confirm that these elements were integrated into the associated RWPs. The RWP/ALARA planning packages included:

• Disassemble and Move Reactor Head to Stand (RWP P03-5102);

• Reactor Head Reassembly and Refueling Close-Out Activities (RWP P03-5108);

• Scaffold Work in Containment (RWP P03-5306);

• Install and Remove Nozzle Dams in [Steam Generators] E-50A/B (RWP P03-5150);

• Removal/Install ICI [In-Core Instrumentation] Flanges and Associated Tasks (RWP P03-5111); and

• NDE [Non-Destructive Evaluation] Bare Metal Inspection on N-50 Reactor Head (RWP P03-5503).

The inspectors also attended the mid-outage Station ALARA Committee Meeting and reviewed RP/Operations-coordinated dose rate reduction activities (e.g., shield package installation, timing of forced oxidation) to further assess inter-departmental coordination and ownership in the radiological work/ALARA planning and scheduling processes.

b. Findings

No findings of significance were identified.

.2 Job Site Inspections and ALARA Controls

a. Inspection Scope

The inspectors observed work activities in the RRA that were performed in radiation areas, HRAs, and locked HRAs to evaluate the use of ALARA controls. Specifically, the inspectors reviewed radiological surveys, attended pre-job radiological briefings, and assessed job site ALARA controls, at least in part, for the following work activities:

• Removal of Reactor Head Inspection Platforms (RWP P03-5100 - Westinghouse Crane and Rigging Activities);

• Steam Generator Eddy Current Testing (ECT) (RWP P03-5152 - Installation of ROSA [Remotely Operated Service Arm], ECT and Tube Plugging);

• Steam Generator Secondary Side Sludge Lance Operations (RWP P03-5155 -

Secondary Side Steam Generator Inspection); and

• Perform Under Reactor Head Inspections/Measurements (RWP P03-5503 -

NDE Bare Metal Inspection on N-50 Reactor Head).

Worker instruction requirements, including protective clothing, engineering controls to minimize dose exposures, the use of predetermined low dose waiting areas, as well as the on-the-job supervision by the work crew leaders and RP technicians, were observed to determine if the licensee had maintained the radiological exposure for these work activities ALARA. Enhanced job controls including RP technician use of electronic teledosimetry and cameras was also evaluated to assess the licensees ability to maintain real time doses ALARA in the field.

b. Findings

No findings of significance were identified.

.3 Radiation Worker Performance

a. Inspection Scope

The inspectors observed radiation workers performing the activities described in Section 2OS2.2 and evaluated their awareness of radiological conditions, personal electronic dosimetry alarm set points, and their implementation of applicable radiological controls.

b. Findings

No findings of significance were identified.

.4 Verification of Dose Estimates, Dose Trending, and Dose Tracking Systems

a. Inspection Scope

The inspectors reviewed the licensees total outage dose estimates, selected individual job dose estimates and the related dose trending for the refueling outage. The ALARA In-Progress reviews for RWP Nos. P03-5102 and P03-5150 were examined to evaluate the licensees ability to assess the effectiveness of the ALARA plans in a timely manner and institute changes in the plan or its execution, if warranted. The licensees dose tracking system was also reviewed to determine if the level of dose tracking detail, dose report timeliness, and report distribution were sufficient to support the control of collective and individual dose.

b. Findings

No findings of significance were identified.

.5 Declared Pregnant Worker Program

a. Inspection Scope

The inspectors reviewed the controls implemented by the licensee for workers who voluntarily entered the licensees fetal protection program. The inspectors assessed the licensees adherence to the requirements contained in 10 CFR 20.1208 and station procedures by reviewing the licensees tracking and evaluation of the dose to the workers embryos/fetuses. Specifically, the inspectors examined the licensees program to ensure that any declared pregnant workers monthly and cumulative exposure for the gestation period were controlled so as not to exceed regulatory limits.

b. Findings

No findings of significance were identified.

.6 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed licensee CRs completed in conjunction with the refueling outage which focused on ALARA planning and controls. The inspectors reviewed these documents to assess the licensees ability to identify repetitive problems, contributing causes, the extent of conditions, and develop corrective actions intended to achieve lasting results.

b. Findings

No findings of significance were identified.

SAFEGUARDS

Cornerstone: Physical Protection (PP)

3PP4 Security Plan Changes (71130.04)

a. Inspection Scope

The inspectors reviewed Revision 47 to the Palisades Nuclear Plant Security Plan to verify that changes did not decrease the effectiveness of the submitted document. The referenced revision was submitted in accordance with 10 CFR 50.54(p) by licensee letter dated January 10, 2003.

Findings No findings of significance were identified.

4OA1 Performance Indicator Verification

a. Inspection Scope

The inspectors verified that the data submitted by the licensee was accurate and complete for the following two Performance Indicators:

• Emergency Diesel Generator Unavailability; and

• Safety System Functional Failures.

The inspectors reviewed control room logs, licensee monthly operating reports, and the licensees corrective action system to verify that the licensee had accurately reported the emergency diesel generator unavailability and safety system functional failures performance indicators for January 2002 through December 2002.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Right Channel Hydrogen Monitor Line Caps Found Removed

a. Inspection Scope

The inspectors reviewed the root cause evaluation associated with the following Condition Report:

• CAP0322269, Right Channel Monitor Line Caps Found Removed During Technical Specification Surveillance Test RT-71P.

The inspectors verified that the following attributes were adequately addressed in the licensees evaluation and associated corrective actions:

• Consideration of extent of condition, generic implications, common cause and previous occurrences;

• Classification and prioritization of problem resolution was commensurate with safety significance;

• Root and contributing causes were identified;

• Corrective actions were appropriately focused to correct the problem and were implemented in a timely manner commensurate with the safety significance; and

• Implementation of longer term corrective actions appear appropriate and adequate compensatory actions were in place to minimize a problem until the permanent action was completed.

The inspectors also discussed the corrective actions and associated evaluations with applicable site personnel including the condition report evaluators and system engineers.

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report (LER)02-003, Inoperable Containment Hydrogen

Monitors

a. Inspection Scope

The inspectors reviewed Licensee Event Report 02-003, Inoperable Containment Hydrogen Monitors, to verify that the event was accurately described, to determine if any violations of NRC requirements had occurred and to assess the appropriateness of identified corrective actions.

b. Findings

Introduction The inspectors determined that a self-revealed Green finding was associated with a Non-Cited Violation of Technical Specification Section 3.3.7 for the failure to restore an inoperable channel of containment hydrogen monitoring within the allowed outage times contained in Technical Specification Action Statements 3.3.7.A and 3.3.7.D.

Description On December 21, 2002, during the performance of a surveillance test, the licensee discovered that the pipe caps for two test taps on the right channel containment hydrogen monitor instrument lines were not installed. The uninstalled pipe caps prevented the surveillance from being completed satisfactorily which prompted licensee personnel to identify the problem.

The containment hydrogen monitor is utilized to sample the containment atmosphere for hydrogen concentrations following a design basis accident to determine if additional actions are needed to abate high hydrogen concentrations. The two test taps were located between the outermost containment isolation valve and the next control valve on the hydrogen monitor instrument line. Therefore, if the right channel hydrogen monitor was placed in service following an accident then the following would have occurred:

C The first test tap without a pipe cap would result in a hydrogen sample being returned to the auxiliary building instead of being returned to containment; C

The second test tap without a pipe cap could open a path from the auxiliary building atmosphere to the hydrogen monitor sample pump such that when containment was at or below auxiliary building pressure, the hydrogen sample would be diluted and the hydrogen monitor would display a value less than the actual hydrogen concentration in containment; and C

Following an accident, if containment pressure was greater than auxiliary building pressure then both taps could be pressurized by containment atmosphere resulting in a release to the auxiliary building.

Licensee personnel completed a root cause evaluation for this event and concluded that the pipe caps were not placed back on the test taps after the Containment Integrated Leak Rate Test, Test RT-36, was last performed in the April 2001 refueling outage.

Licensee personnel also concluded that the failure to reinstall the test tap pipe caps was attributable to human performance failures involving inadequacies in procedure compliance and independent verification policies when completing prescribed procedure actions. The inspectors determined that the conclusions were reasonable.

The inspectors determined that the failure to ensure that the right channel hydrogen monitoring system was aligned properly after the system was restored from testing during the 2001 refueling outage was a self-revealed licensee performance deficiency which 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 February 21, 2003. The finding dealt with maintaining the functionality of containment and was related to the barrier integrity cornerstone attribute regarding configuration control. The cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events was affected.

Specifically, the human performance deficiencies which resulted in the failure to ensure that the pipe caps were installed after testing was completed in April 2001 resulted in the right channel hydrogen monitor being inoperable. Consequently, the hydrogen monitor was incapable of measuring a representative hydrogen concentration in the containment atmosphere following an accident. In addition, the uninstalled pipe caps also represented a potential radiological release path if the hydrogen monitor had been placed in service following an 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 finding represented an actual open pathway in the physical integrity of reactor containment which required additional analysis using Manual Chapter 0609, Appendix H, Containment Integrity SDP. Utilizing Appendix H, the inspectors determined the finding was potentially risk significant.

A Region III Senior Reactor Analyst in conjunction with the inspectors performed a Phase 3 assessment. Utilizing NUREG-1675, Basis Document for Large Early Release Frequency (LERF) Significance Determination Process (SDP), the analyst determined that a containment leak rate of 100 volume percent per day constitutes the threshold for LERF significance. The 100 volume percent per day leakage rate is approximately equivalent to an opening size in the containment of 2.5 to 3 inches in diameter for Pressurized Water Reactors with large dry containments, thus the significance of this finding was found to be very low as the actual combined open pathways from both test taps was less than 0.5 inches in diameter.

Therefore, the finding was determined to be of very low safety significance (Green).

Enforcement Technical Specification 3.3.7 requires, in part, that two containment hydrogen monitor channels be operable in Modes 1, 2 and 3. Technical Specification Action Statement 3.3.7.A requires, in part, that when one or more functions with one required containment hydrogen monitor channel is inoperable then the required channel be restored to an operable status within 30 days or a report to the NRC be initiated in accordance with Technical Specification 5.6.6. In addition, Technical Specification Action Statement 3.3.7.D requires, in part, that when two containment hydrogen monitor channels are inoperable that one channel is restored to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in hot shutdown within the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

Contrary to the above, from May 2001 through June 2001 and January 2002 through December 2002, while the plant was in Mode 1, the right channel containment hydrogen monitor was inoperable because the pipe caps for two test taps were not installed. In addition, in November 2002, while the plant was in Mode 1 with the right channel containment hydrogen monitor inoperable, the left channel containment hydrogen monitor was also inoperable for approximately 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> because of scheduled maintenance.

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 Technical Specification 3.3.7, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 50-255/03-02-03)

This issue was entered in the licensees corrective action program as Condition Report CAP0322269, Right Channel Monitor Line Caps Found Removed During Technical Specification Surveillance Test RT-71P. This LER is closed.

.2 (Closed) LER 02-002, Automatic Reactor Trip and Safety System Actuation

a. Inspection Scope

The inspectors reviewed LER 02-002 to verify that the event was accurately described, determine if any violations of NRC requirements had occurred and to assess the appropriateness of identified corrective actions.

This issue was previously documented in Inspection Report 50-255/02-09 as a self-revealed Green finding and associated 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 KV transmission lines that connect the plant and switchyard.

The inspectors did not identify any new information in the LER which was of concern and concluded that the completed and planned corrective actions were reasonable.

Therefore, this LER is closed.

b. Findings

No findings of significance were identified.

.3 (Closed) LER 03-001, Inoperable Steam Generator Low-Level Channels

a. Inspection Scope

The inspectors reviewed LER 03-001 to verify that the event was accurately described, determine if any violations of NRC requirements had occurred and to assess the appropriateness of identified corrective actions.

On January 15, 2003, at 8:15 p.m. licensee personnel identified that all four steam generator reactor protection system low-level trip setpoints on both steam generators were set below the allowable value specified in Technical Specification 3.3.1, Reactor Protective System Instrumentation. Consequently, all steam generator low-level trip instrument channels were declared inoperable and Technical Specification 3.0.3 was entered which required action be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to shut down the plant to Mode 3, Hot Standby, within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />.

Licensee personnel requested and received enforcement discretion from the NRC to extend the completion times in Technical Specification 3.0.3 by an additional 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> in order to conduct online repairs. Licensee personnel subsequently adjusted the trip setpoints to comply with Technical Specification requirements and the steam generator low-level reactor protection system trip functions were declared operable within the extended time allowed by the enforcement discretion. The enforcement discretion related to this event is discussed in Section 4OA5.3 of this report.

Licensee personnel evaluated this event and subsequently determined that the low-level trip setpoints had been set incorrectly since 1998. The event was caused by a vendor calculation error that was not previously identified and resulted in a biasing correction factor being applied to the level transmitters in the non-conservative direction.

This finding was more than minor because it affected the mitigating systems cornerstone objective by impacting the reactor protection systems capability to respond to a steam generator low-level initiating event to prevent undesirable consequences. However, while the steam generator low-level setpoints were below the allowable values specified in Technical Specifications, all the low-level setpoints were greater than the analytical values specified in the plant safety analysis. Therefore, plant safety would have been maintained during a steam generator low level initiating event.

The finding affected the mitigating systems cornerstone and was determined to be of very low safety significance (Green) using NRC Manual Chapter 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, because the finding:

C was not a design or qualification deficiency; C

did not represent the loss of the reactor protection systems safety function; and C

did not screen as potentially risk significant due to seismic, fire, flooding, or severe weather initiating event.

This licensee identified finding involved a violation of Technical Specification 3.3.1, Reactor Protective System Instrumentation, and the related enforcement aspects are discussed in Section 4OA7 of this report. This LER is closed.

b. Findings

No findings of significance were identified.

.4 Declared Unusual Event Due to Unexplained Service Water Bay Lowering Level

a. Inspection Scope

The inspectors reviewed the circumstances associated with the Unusual Event on February 16, 2003, which was declared due to the unexplained lowering level in the service water bay. The resident inspectors provided 24-hour site coverage after the Unusual Event was declared to monitor the licensees event response until the Unusual Event was terminated on February 19, 2003.

The inspectors reviewed the circumstances surrounding this event to assess whether any licensee performance issues existed which contributed to the initiation of the event.

Licensee operator response during the event was assessed under Personnel Performance Related to Non-Routine Plant Evolutions and Events, in Section 1R14.1 of this report.

b. Findings

Introduction No findings of significance or licensee performance deficiencies were identified during the inspectors review of the events which occurred. However, the inspectors did note that NUREG-0820, Integrated Plant Safety Assessment - Systematic Evaluation Program - Palisades Plant, refers to the ability of the plant to utilize a warm water recirculation pump as an alternate supply for the service water pumps if catastrophic damage were to occur to the intake pipe or other components that completely block intake flow. However, the warm water recirculation pump currently does not have the ability to perform this function; therefore, the inspectors opened an Unresolved Item to track whether or not the licensee is in nonconformance of commitments made in the Systematic Evaluation Program.

Description On February 16, 2003, at approximately 1:50 a.m. the Control Room received a service water bay low level alarm. The operators determined that there was reduced flow from the service water intake structure in Lake Michigan as opposed to an equipment problem in the plant. At 02:53 a.m. the Site Emergency Director declared an Unusual Event based on the Miscellaneous Emergency Action Level, due to the lowering service water bay levels. Operators responded by taking the manual actions specified in Alarm Response Procedure 7 and Off-Normal Procedure 6.1, Loss of Service Water.

Operator actions included securing the dilution water pumps, which were the largest service water load, lowering plant power level from 100 percent to approximately 90 percent and initiation of warm water recirculation to the service water bay from the make-up basin through the use of Pump P-5. Actions taken by the operators successfully stabilized level in the service water bay.

On February 16, 2003, divers performed inspections which identified that at least two sides of the intake crib appeared to be encased in frazil ice. Adverse weather conditions prevented the divers from inspecting all four sides of the intake crib. Licensee personnel also learned that municipal water plants on the eastern shore of Lake Michigan experienced the same phenomenon of frazil ice forming on the intake cribs. The Unusual Event was terminated on February 19, 2003, after inspections were completed of the intake crib and intake piping which revealed that no frazil ice remained and that the intake crib and piping was not damaged.

The inspectors reviewed industry operating experience and concluded that a performance issue did not exist with regard to this event. The licensees procedures contained the appropriate actions to abate the formation of frazil ice on the intake structure, mainly by reducing the largest service water loads and reducing plant power.

However, the inspectors did note that NRC NUREG-0820, Systematic Evaluation Program for the Palisades Nuclear Plant, contained commitments the licensee made to the NRC during the Integrated Assessment Program which were referenced in Updated Final Safety Analysis Report (UFSAR) Section 1.8.1, Systematic Evaluation Program, and Table 1.3.

Specifically, Section 4.7.1, Cooling Water System Structures Inspection, of NUREG-0820, referenced in UFSAR Table 1.3, states in part that the NRC staff determined that inspection of cooling water systems and structures as referenced in Regulatory Guide 1.127 did not have to be made, in part, because An alternate water supply for the service water pumps is available independent of the normal intake path.

This alternate supply is piped to the intake structure from the warm water recirculation pump (can be powered from emergency diesel generator) and takes a suction from the mixing basin or from the lake at the discharge structure.

However, the ability for the warm water recirculation pump to take a suction from the lake was not currently available due to the suction pipe being buried in sand. Also, the ability to take a suction from the mixing basin has not been available since the year 2000 due to the low levels in Lake Michigan.

The licensee initiated Condition Report CAP033802, Warm Water Recirculation Pump P-5, Potential Commitment Nonconformance, to evaluate this issue. The inspectors opened an Unresolved Item to track the licensees evaluation of this potential nonconformance of a commitment from the Systematic Evaluation Program.

(URI 50-255/03-02-04)

.5 Declared Alert Due to a Fire With The Potential To Affect Safety-Related Equipment

a. Inspection Scope

The inspectors responded to the plant after an Alert was declared at 8:47 p.m. on March 18, 2003. The plant was in Mode 5, Cold Shutdown, when a fire alarm activated in the cable spreading room. Fire brigade personnel responded and reported a significant amount of smoke in the cable spreading room which prompted the Alert declaration due to a fire with the potential to affect safety-related equipment. The inspectors monitored licensee actions during the event and verified that the shutdown cooling system remained in service to remove reactor decay heat. The event was terminated at 11:26 p.m. on March 18, 2003, after the licensees preliminary investigation determined that the likely cause of the smoke was the circuit breaker for Charging Pump P-55A which was found damaged. This event was the subject of an NRC special inspection and the event details were documented in Inspection Report 50-255/03-05(DRP).

b. Findings

Findings associated with this event will be documented in NRC Special Inspection Report 50-255/03-05(DRP).

.6 Declared Alert Due to Loss of Offsite Power

a. Inspection Scope

On March 25, 2003, an Alert was declared at 11:21 a.m. after offsite power to the plant was lost unexpectedly which resulted in a loss of shutdown cooling to the reactor. The inspectors responded to the control room and observed the operators response to the event to ensure that appropriate plant procedures were utilized in an accurate and timely manner. The inspectors verified that Off-Normal Procedure 17, Loss of Shutdown Cooling, General Operating Procedure 14, Shutdown Cooling Operations, and Off-Normal Procedure 2.1, Loss of AC Power, were implemented as required to restore shutdown cooling and mitigate the event. The inspectors also verified that the Emergency Plan was implemented in an accurate and timely manner.

The inspectors walked down the control room panels to monitor key plant parameters including the primary coolant system temperature heatup rate. The inspectors also verified that the emergency diesel generators were operating properly in order to provide power to plant equipment necessary to re-establish shutdown cooling to the reactor.

The Alert emergency was downgraded to an Unusual Event after shutdown cooling was restored to the reactor with the shutdown cooling pump being powered from the emergency diesel generator. The inspectors provided 24-hour site coverage to monitor licensee actions until the Unusual Event was terminated on March 27, 2003, after offsite power to the plant was restored and the emergency diesel generators were secured.

This event was the subject of an NRC special inspection and the event details will be documented in Inspection Report 50-255/03-05(DRP).

b. Findings

Findings associated with this event will be documented in NRC Special Inspection Report 50-255/03-05(DRP).

4OA5 Other Activities

.1 (Closed) Unresolved Item (URI) 50-255/02-03-02:

Potential 125VDC Single-Failure Impact on Containment Spray In Inspection Report 50-255/02-03, Section 1R21.b.2, NRC inspectors documented a potential single-failure scenario whereby the containment spray system would be non-functional during a loss-of-coolant accident. At the end of the inspection, this issue was characterized as a finding that had a credible impact on safety, in that the plant may have been operated outside of the design basis. The issue was characterized as unresolved pending an Office of Nuclear Reactor Regulation (NRR) licensing basis determination.

To resolve this issue, discussions were held with NRR to review the Palisades licensing basis and determine whether the plant was licensed with breaker and fuse failures considered as passive. Participants in those discussions were staff from NRR projects and the electrical branch, and Region III staff. As a result of the discussions, NRR confirmed that breakers and fuses which did not have to change state to accomplish the intended safety function, as those involved in the scenario, were considered passive devices.

As discussed in the inspection report, NRR was requested to determine whether a backfit, in accordance with 10 CFR 50.109, to conform with present regulatory and industry guidance was appropriate. It was determined, that because of the extremely low probability of a large break loss-of-coolant accident coincident with the occurrence of the proposed single failure, a backfit could not be justified. This URI is closed.

.2 (Closed) Violation (VIO) 50-255/01-08-01, Smoke Detectors Inadequate - Northwest

Portion of Cable Spreading Room During a triennial fire protection inspection completed in September 2001, the NRC identified a finding of to be determined significance and associated Apparent Violation (AV) 50-255/01-08-01 regarding inadequate smoke detectors in the northwest portion of the cable spreading room.

The NRC subsequently characterized the finding as White (i.e. an issue with low to moderate safety significance, which may require additional NRC inspections) in a letter dated October 26, 2001, from the NRC to Mr. Douglas E. Cooper, Site Vice President, Palisades Nuclear Plant, Nuclear Management Company, LLC. A Notice of Violation was also issued with the White finding. Nuclear Management Company did not contest the violation or the characterization (White) of the risk significance for the finding.

On July 25, 2002, the NRC completed a supplemental inspection in accordance with Inspection Procedure 95001 which assessed the adequacy of the corrective actions for the White finding and associated violation. The inspection was documented in Inspection Report 50-255/02-08(DRS).

During the supplemental inspection, the inspectors concluded that the licensee had developed a comprehensive corrective action plan to address the issue as well as any other historical NFPA (National Fire Protection Association) code conformance issues.

The inspectors also concluded that adequate measures were in place to prevent a similar occurrence from recurring. Therefore, this violation is closed.

.3 (Closed) Unresolved Item 50-255/03-02-05:

Review of Notice of Enforcement Discretion (NOED) 03-3-001 For Nuclear Management Company LLC Regarding Palisades The inspectors reviewed the circumstances associated with issuing NOED 03-3-001 and the basis for the NOED request to determine if a failure to comply with regulatory requirements contributed to the need for enforcement discretion. The inspectors also verified that licensee personnel complied with the compensatory actions noted in the NOED.

On January 15, 2003, at 8:15 p.m. licensee personnel identified that all four steam generator reactor protection system low-level trip setpoints on both steam generators were set below the allowable value specified in Technical Specification 3.3.1, Reactor Protective System Instrumentation. Consequently, all steam generator low-level trip instrument channels were declared inoperable and Technical Specification 3.0.3 was entered which required that action be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to shut down the plant and that the plant be in Mode 3, Hot Standby, within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. Licensee personnel requested enforcement discretion to extend the completion times in Technical Specification 3.0.3 by an additional 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> to avoid a plant shutdown and conduct repairs online.

The NRC verbally granted NOED 03-3-001 at 12:07 a.m. on January 16, 2003.

Licensee personnel subsequently adjusted the trip setpoints to comply with Technical Specification requirements and the steam generator low-level reactor protection system trip functions were declared operable at 8:00 p.m. on January 16, 2003.

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. Therefore, this URI is closed.

This issue was determined to be a licensee identified finding which involved a violation of Technical Specification 3.3.1, Reactor Protective System Instrumentation. The event is discussed further in Section 4OA3.3 of this report and the related enforcement aspects for the violation are discussed in Section 4OA7 of this report.

4OA6 Meetings

.1 Exit Meeting

The inspectors presented the inspection results to Mr. D. Cooper and other members of licensee management on April 11, 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 Meeting

Interim Exit was conducted for:

• Physical Protection Inspection with Mr. B. Rowland on January 31, 2003.

• Radiation Protection Inspection with Mr. D. Cooper on April 2, 2003.

4OA7 Licensee Identified Violations

The following finding of very low safety significance (Green) was identified by the licensee and was a violation of NRC requirements which met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a Non-Cited Violation.

C Technical Specification 3.3.1, Reactor Protective System Instrumentation, required, in part, that four reactor protective system trip units including the associated steam generator low-level instrument channels be operable in Mode 1. Contrary to this, on January 15, 2003, with the plant in Mode 1, all steam generator low-level instrument channels on both steam generators were determined to be inoperable. This event was documented in the licensees corrective action program as CAP032931, Level Transmitter Static Pressure Effect Not Incorporated Correctly. This finding was of very low safety significance because the finding did not represent the loss of the reactor protection systems safety function.

KEY POINTS OF CONTACT Licensee D. Cooper, Site Vice President P. Harden, Director, Engineering G.W. Hettel, Manager, Maintenance and Construction D. G. Malone, Supervisor, Regulatory Assurance D. J. Malone, General Plant Manager C. Moeller, ALARA Supervisor G. Packard, Operations Manager R. Remus, Assistant Plant Manager B. Rowland, Security Manager P. Russell, Manager Performance Improvement NRC J. Eads, Project Manager, NRR E. Forrest, NRR J. Hayes, NRR J. Creed, Branch Chief, Safeguards H. Walker, NRR LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-255/03-02-01 NCV Inadequate Corrective Actions to Address Scaffolding Control Problems 50-255/03-02-02 NCV Inadequate Testing of the Fuel Handling Area Ventilation System 50-255/03-02-03 NCV Failure to Restore an Inoperable Channel of Hydrogen Monitoring 50-255/03-02-04 URI Nonconformance with Systematic Evaluation Program Commitment (Section 4OA3.4)50-255/03-02-05 URI Review of Notice of Enforcement Discretion (NOED) 03-3-001 Closed 50-255/03-02-01 NCV Inadequate Corrective Actions to Address Scaffolding Control Problems 50-255/03-02-02 NCV Inadequate Testing of the Fuel Handling Area Ventilation System 50-255/03-02-03 NCV Failure to Restore an Inoperable Channel of Hydrogen Monitoring 50-255/03-02-02 URI Potential 125VDC Single-Failure Impact on Containment Spray 50-255/01-08-01 VIO Smoke Detectors Inadequate - Northwest Portion of Cable Spreading Room 50-255/02-003 LER Inoperable Containment Hydrogen Monitors 50-255/02-002 LER Automatic Reactor Trip and Safety System Actuation 50-255/03-001 LER Inoperable Steam Generator Low-Level Channels 50-255/03-02-05 URI Review of Notice of Enforcement Discretion (NOED) 03-3-001 LIST OF ACRONYMS USED ALARA As-Low-As-Is-Reasonably-Achievable ASME American Society of Mechanical Engineers AV Apparent Violation CFR Code of Federal Regulations CR Condition Report CY Calendar Year DRP Division of Reactor Projects DRS Division of Reactor Safety ECT Eddy Current Testing GL Generic Letter HDR High Dose Rate HEPA High Efficiency Particulate Air HRA High Radiation Area HSAS Homeland Security Advisory System ICI In-Core Instrumentation ICM Interim Compensatory Measures IMC Inspection Manual Chapter LER Licensee Event Report LERF Large Early Release Frequency NCV Non-Cited Violation NDE Non-Destructive Evaluation NFPA National Fire Protection Association NMC Nuclear Management Company NOED Notice of Enforcement Discretion NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation OHS Office of Homeland Security RIS Regulatory Information Summary ROSA Remotely Operated Service Arm RRA Radiologically Restricted Area RWP Radiation Work Permit SDP Significance Determination Process UFSAR Updated Final Safety Analysis Report URI Unresolved Item LIST OF

DOCUMENTS REVIEWED

1R04

Equipment Alignment

Plant Procedures and Miscellaneous Documents

SOP-12

System Operating Procedure - Auxiliary

Feedwater

Revision 14

DBD-1.03

Design Basis Document - Auxiliary Feedwater

System

Revision 6

M-207, Sheet 2

Piping and Instrument Diagram - Auxiliary

Feedwater

Revision 32

M-17, Sheet 41

Auxiliary Feedwater Mini Flow Valves

Revision B

Open Work Order/Work Requests on the

Auxiliary Feedwater System

Condition Reports Reviewed to Assess Characterization of Identified Problems

CAP033714

MV-ES502 Outlet is not Capped as Shown on

PID - 204, Sheet 1B

CAP033541

Technical Issue Regarding the Removal of

Auxiliary Feedwater Pumps Start-up Strainers

CAP033346

Discrepancies Noted in Safeguard Rooms by

NRC

CAP033503

Licensing Basis Requirements of High Energy

Line Break of Auxiliary Feedwater Outside

Containment

CAP033667

Seismic Scaffold Does Not Meet Installed Plant

Equipment Separation Requirements

CAP033627

Piping and Instrument Diagram Updated Prior to

Associated Procedure Change

CAP033630

Auxiliary Feedwater Pumps P-8A and P-8B

Cooling Water Outlet Valves not Locked

CAP033744

Seismic Scaffold Found that Did Not Appear to

Meet Equipment Separation Requirement

Condition Reports Reviewed to Assess Corrective Actions

CAP030979

Inconsistency Noted Between Configuration of

Auxiliary Feedwater and Emergency Core

Cooling System Pump Cooling Water Valves

CAP031074

Emergency Feed Supply Line to AFW Pumps

Subjected to Sand Accumulation

1R05

Fire Protection

Plant Procedures

FP-MS-1

Fire Protection Check Sheet - Monthly Inspection

and Testing of Fire Doors for Fire Areas 1, 15, 16

Revision 2

FPSP-SI-1

Data Sheet for Alarm Bells and Ionization Smoke

Detectors for Fire Areas 1, 15, 16

Revision 2

FPSP-RP-11

Fire Barrier Penetration Seal/Conduit Seal

Inspection Form for Fire Areas 1, 8, 15, and 16

Revision 4

FPSP-WP-1

Safety-Related Fire Door Data Sheet Fire

Areas 1, 8 and 15

Revision 1

FPSP-SO-2

Safety-Related Fire Door Data Sheet for Fire

Areas 1, and 15

Revision 0

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

Safety-Related Equipment

Revision 12

ONP25.2

Off-Normal Procedure - Alternate Safe Shutdown

Procedure

Revision 18

FP-MS-1

Fire Protection Check Sheet Monthly Inspection

and Testing of Fire Doors Fire Area 1, 15

Revision 2

FPSP-RI-2

Ionization Smoke Detector Locations,

Containment Building, Attachment 2

Revision 1

FPSP-RP-12

Fire Rated Assembly/Fire Protection Assembly

Checkoff/Comment Sheet

Revision 2

FPSP-RO-8

Containment Building Fire Hose Replacement,

Nozzle Inspection and Station Valve Check

Revision 1

FPSP-RO-9

Fire Sprinkler System Inspection

Revision 0

Miscellaneous Documents

EA-PSSA-00-001

Palisades Plant Post Fire Safe Shutdown

Summary Report, for Fire Areas 1, 8, 14, 15, and

Revision 1

Palisades Plant

Fire Hazards

Analysis

Analysis for Fire Areas 1, 8, 14, 15, and 16

Revision 4

Palisades Plant

Fire Hazards

Analysis

Analysis for Fire Areas 1, 8, 14, 15, and 16

Revision 4

BTP ASB 9.5-1

U.S. NRC Branch Technical Position 9.5-1 -

Guidelines for Fire Protection for Nuclear Power

Plants

Revision 1

Consumer Power Company - List of Changes

and Response to Appendix A to Branch

Technical Position APCSB 9.5-1 and Regulatory

Guides 1.78 and 1.101

Revision 2

August 24, 1996

FSAR 9.6

Updated Final Safety Analysis Report,

Section 9.6 - Fire Protection

Revision 23

EA-APR-98-008,

Section 4.4

Analysis of Specific Barrier Segments; Fire

Barrier Segment 147C/149F (Auxiliary Building

@ EL 613'6")

1R07

Heat Sink Performance

T-390

Special Test - Single Tube Testing of the

Component Cooling Water Heat Exchangers

completed March 21, 2003

Revision 0

1R11

Licensed Operator Requalification

SIS-JPM-06

Job Performance Measure, Fill an SI Tank

Revision 0

PPCS-JPM-01

Job Performance Measure, Alternate

Pressurizer Pressure Channels

Revision 0

EDG-JPM-01A

Job Performance Measure, Start and Load a

D/G in Parallel

Revision 0

AP 4.05, Attachment

Completed Operator Performance

Evaluations, for 1 SRO and 3 ROs

January 24, 2003

Condition Reports Reviewed to Assess Problem Identification Characterization

CAP033270

Review Expectations for Time to Classify with

SEDs and EOF Directors

1R13

Maintenance Risk Assessments and Emergent Work Evaluation

Miscellaneous Documents

Equipment and System Operational Guidance

Recommendation #117, Intake Crib (Ultimate

Heat Sink) Operable but Degraded

February 17, 2003

Operations Log Entries for January 7-12, 2003;

February 6-7, 11 and 17-21, 2003; March 18-23

and 25-27, 2003

Scheduled Maintenance Activities for January 7-

2, 2003; February 6-7, 11 and 17-21, 2003;

March 18-23 and 25-27, 2003

Operators Risk Reports for January 7-12, 2003;

February 6-7, 11, 17-21, 2003

Shift Activities Sheets, Operations, March 18 - 23

and 25-27, 2003

GOP-14,

16

Shutdown Operation Equipment Sheets,

Shutdown Safety Risk Assessment, March 18-

23, and 25-27, 2003

Condition Reports Reviewed to Assess Characterization of Identified Problems

CAP033470

Bolt Found Missing on Warm Water

Recirculation Pump P-5 Protective Screen

CAP034302

Workers Entered Protected Train Barriers

without SRO Knowledge

CAP033807

Procedure Revision Not Incorporated Into

Ongoing Evaluation

CAP034530

Discrepancies in Diesel Generator Operating

Procedure SOP-22

1R14

Non-Routine Plant Evolutions and Events

Plant Procedures

GOP-8

General Operating Procedure - Power Reduction

and Plant Shutdown to Mode 2 or Mode 3 $ 525°

Fahrenheit

Revision 18

ARP-7

Alarm Response Procedure - Auxiliary Systems

Scheme EK-11 (C-13)

Revision 63

ONP 6.1

Off-Normal Procedure - Loss of Service Water

Revision 10

SOP 15

Service Water System

Revision 25

SOP-22

Emergency Diesel Generators

Revision 34

ONP-2.1

Loss of AC Power

Revision 12

ONP-17

Loss of Shutdown Cooling

Revision 28

Miscellaneous Documents

WO 24113520

Breaker 52-1205: Install Original Breaker When

it Arrives from Vendor

WO 24912222

Breaker 52-1205: Remove 52-1205 Breaker,

Install Spare

Condition Reports Reviewed to Assess Characterization of Identified Problems

CAP033437

Received EK-1129 Service Water Bay Low Level

Alarm

CAP033438

Stop Log Gasket Failure at Mixing Basin

CAP034629

Temporary Modification Not Evaluated for Full

Duration of Expected Implementation

1R15 Operability Evaluations

CAP032499

Damper D-22, Diesel Generator 1-2 Room

Exhaust Damper is Broken on North Side

CAP032787

Code Error Found in Contempt -LT/28

CAP033644

Component Cooling Water Heat Exchanger

Service Water Outlet Control Valve CV-0826

Inoperable

CAP032556

Potential Non-Conservative Minimum Service

Water Temperature Used in the Accident

Analysis

Miscellaneous Documents

Table 14.17.1-4

Safety Analysis, Chapter 14 Table, Fan Cooler

Capacity Used in the LBLOCA Analysis

Revision 23

Condition Reports Reviewed to Assess Characterization of Identified Problems

CAP033644

Component Cooling Water Heat Exchanger

Service Water Outlet Valve CV-0826 Inoperable

CAP033610

Gravity Damper D-29 May Hang Open when

Wind is From the North

Condition Reports Reviewed to Assess Corrective Actions

C-PAL-97-1363

Component Cooling Water System Not Analyzed

For Present LOCA Containment Analysis

1R17

Permanent Plant Modifications

EAR 2001-0601

Install Casing Vent Valves on Low Pressure

Safety Injection Pumps P-67A and P-67B

FDC-24210903-1

Field Design Change for EAR 2001-0601

8-SK-EAR-2001-

0601

Drawing - Pump Casing Vent Valve

Revision B

WO 24210903

Install LPSI Pump Casing Vent Valve

Condition Reports Reviewed to Assess Characterization of Identified Problems

CAP033868

Work Not Released Prior to Commencing Work

CAP033869

LPSI Pump P-67B - As Found Anomalies

Discovered During Power End / Seal

Replacement

CAP033870

LPSI Pump P-67B Impeller Retaining Nut Found

Loose

CAP033668

Discrepancy Between LPSI Pump P-67A and B

Vendor Drawing and Maintenance Procedure

Drawing

CAP033882

Evidence of Overheating on 52-1101 Circuit

Breaker Rear Bus Stabs

CAP033878

2-111 LPSI P-67B Anomalous Behavior

CAP033903

Differential Pressure Trend Increasing for LPSI

P-67B

CAP033905

Problems Encountered with Vent Line Addition to

P-67B Casing

CAP033906

Possible Excessive Play in P-67B Bearing

Housing

CAP033943

Final Field Dimensions on P-67Bs Pump Casing

Vent Not Acceptable for Growth

CAP033451

LPSI Pump P-67B Case Vent Valve Pipe May

Crack if Installed per Current Design

1R19

Post Maintenance Testing

Plant Procedures

QO-20,

Inservice Test Procedure - Low Pressure Safety

Injection Pumps, Low Pressure Safety Injection

Pump Test Evaluation; documented test data

completed on March 17, 2003

Revision 12

T-303

Special Test - Emergency Diesel Generator 1-2

Overspeed Trip Setpoint Verification completed

January 24, 2003

Revision 4

MO-7A-2

Emergency Diesel Generator 1-2 completed

January 25, 2003

Revision 54

QI-39

Auxiliary Feedwater Actuation System Logic Test

Revision 0

ARP-7

Annunciator Number 29, Service Water Pump

Bay Lo-Level

QO-19

Inservice Test Procedure - HPSI Pumps and

ESS Check Valve Operability Test completed on

December 28, 2002

Revision 22

Work Orders

24320249

Work Order - K-6B, EDG 1-2; Inspect and Adjust

Fuel Rack

24320159

LS-0752D, Auxiliary Feedwater Pump P-8B

Automatic Start

24320154

LS-0451C, Auxiliary Feedwater Pump P-8A

Automatic Start

24320144

LA-0751A, RPS Channel A S/G 1 Lo Level

Bistable Trip Unit

24320149

LA-0752B, RPS Channel B S/G 2 Lo Level

Bistable Trip Unit

24320562

LIA-1338, Level Indicating Alarm for Service

Water Bay Level

214528

P-66A, High Pressure Safety Injection Pump

Miscellaneous Documents

Condition Reports Reviewed to Assess Characterization of Identified Problems

CAP034409

LPSI P-67B Vibration in the Alert Range of

QO-20

CAP034038

LPSI P-67B Pump Motor Unable to be Aligned

Within Specifications

CAP033099

K-6B Failed to Stop after Overspeed Trip Test

1R20

Refueling and Other Outage Activities

Plant Procedures

GOP-14

Shutdown Cooling Operations

Revisions 14, 15, 17

ONP-17

Loss of Shutdown Cooling

Revision 28

SOP-1

Primary Coolant System

SOP-3

Safety Injection and Shutdown Cooling System

GOP-14,

16

Shutdown Operation Equipment Sheets

WI-PCS-M-06

Work Instruction - NSSS Walkdown

Revision 0

Miscellaneous Documents

EOOS Review of REFOUT-3 Schedule for

GOP 14 Compliance

February 26, 2003

EOOS Review of REFOUT-3 Schedule for

GOP 14 Compliance

March 16, 2003

GOP-14 EOOS compliance review - 2 week look

ahead for 3/16/03 - 3/29/03

March 18, 2003

Plant computer data for primary coolant system

cooldown rate and primary coolant system loop

temperatures

March 15-17, 2003

Palisades Daily Refout Status sheets and

Operations Shift Briefing packages

GL 88-17

Generic Letter, Loss of Decay Heat Removal

October 17, 1988

Licensee 60 Day response to GL 88-17

January 3, 1989

Licensee 90 Day response to GL 88-17

January 31, 1989

Condition Reports Reviewed to Assess Characterization of Identified Problems

CAP034061

Gray Duct Tape Found on Quench Tank Vent

Line

CAP034334

Boron Accumulation on HPSI Subcooling Control

Valve CV-3071

1R22

Surveillance Testing

Completed Technical Specification Surveillance Tests

RO-138B

Emergency Escape Air Lock Interlock

Verification

Completed

January 23, 2003

RT-85D

Inplace HEPA and Charcoal Filter Testing

Control Room Ventilation B Train

Completed

February 14 and 17,

2003

RT-85D

Inplace HEPA and Charcoal Filter Testing

Control Room Ventilation A Train

Completed

January 11 and

February 4, 2003

RT-85C

Inplace HEPA and Charcoal Filter Testing -

VF 66

Completed March 3,

4, 15 and 16th

RO-105

Full Flow Test for SIT Check Valves and PCS

Loop Check Valves completed March 27, 2003;

in addition to previously completed tests

Revision 7

RO-32-50

LLRT - Local Leak Rate Test Procedure for

Escape Air Lock completed January 29, 2003

Revision 0

RE-131

Diesel Generator 1-1 Load Reject

Revision 2

T-302

Emergency Diesel Generator 1-1 Overspeed Trip

Setpoint Verification

Revision 5

RI-3D

Pressurizer Pressure Channel D Calibration

Revision 0

RI-3C

Pressurizer Pressure Channel C Calibration

Revision 0

RI-5D

Steam Generator Pressure Channel D

Calibration

Revision 0

QI-39

Auxiliary Feedwater Actuation System Logic Test

completed February 18, 2003

Revision 0

Miscellaneous Documents

ASME N510-1989

Testing of Nuclear Air Treatment Systems

ANSI N510-1975

Testing of Nuclear Air-Cleaning Systems

PROC EQS-

FLT03

In-Place Testing of Palisades Nuclear Plant

HEPA Filter Systems

PROC EQS-

FLT04

In-Place Testing of Palisades Nuclear Plant

Charcoal Absorber Filter Systems

RG 1.52

NRC Regulatory Guide - Design, Testing, and

Maintenance Criteria for Post Accident

Engineered Safety Feature Atmosphere Cleanup

System

Revision 2

WO 24320373

Work Order - MZ-50 Lights do Not Work

WO 24211054

Work Order - MZ-50 - Inner Door Occasionally

Sticks Closed

Reg Guide 1.9,

Section 2.2

Selection, Design, and Qualification of Diesel-

Generator Units as Standby (Onsite) Electric

Power Systems at Nuclear Power Plants, Test

Descriptions

Revision 3, July

1993

Condition Reports Reviewed To Assess Problem Identification Characterization

CAP033742

Spent Fuel Pool Exhaust Fan V-8B Ductwork is

Separated/Torn (VF-66 Inoperable)

`

CAP033749

Procedure Administrative Weaknesses Found

During Surveillance Peer Checking

CAP033764

Laboratory Services Test Procedures Refer to

Incorrect ASME Std for HVAC Test

CAP033788

RT-85D Visual Inspections Not Performed in

Accordance with TS 5.5.10 Sequence

CAP033792

Damage Found to V-8As Discharge Duct

CAP033829

Spent Fuel Pool Exhaust Fan V-8A was Found to

have Low Air-Flow per TSST RT-85C

CAP033895

Spent Fuel Pool Ventilation Testing not in

Conformance with ASME Standard

CAP033907

Incomplete Set of Visual Inspections Prescribed

by RT-85D and RT-85C on HVAC

CAP033908

RT-85D Improvement Needed to Check

Required Flow Rates

CAP033910

Incorrect Interpretation in RT-85C and RT-85D

Basis Document

CAP033911

Downstream HEPA Filter not tested in RT-85D

for Control Room Ventilation Filter

CAP033337

EDG 1-1 Right Fuel Oil Inlet Header Has Small

Leak Near 1R Cylinder

CAP033333

K-6A, Cylinder 9L is Making Different Noise Than

Other Cylinders

CAP032881

Setpoint Found Out of As-Found Tolerance

During RI-3B

CAP032759

PPC Indicated Reactor Power Unexpectedly

Affected During RI-5B S/G Press Chan Calib

Condition Reports Reviewed to Assess Condition Evaluation and Corrective Actions

CPAL0101259

Discontinuity Observed in PPC Plot for Safety

Injection Tank T-82D Level Transmitter

1R23

Temporary Plant Modifications

Plant Procedures

RI-4A

Technical Specification Surveillance Procedure -

Steam Generator Level Channel A Calibration

Revision 0

RI-4B

Technical Specification Surveillance Procedure -

Steam Generator Level Channel B Calibration

Revision 0

RI-4C

Technical Specification Surveillance Procedure -

Steam Generator Level Channel C Calibration

Revision 0

RI-4D

Technical Specification Surveillance Procedure -

Steam Generator Level Channel D Calibration

Revision 0

Temporary Modification Packages

TM-2003-003

Change the Setpoints and Associated

Tolerances Listed in RI-4A, B, C & D for the Low

Steam Generator Trip and AFAS Trip to the

Values shown on the Attached Marked-Up

Pages

Condition Reports Reviewed To Assess Problem Identification Characterization

CAP032931

Level Transmitter Static Pressure Effect not

Incorporated Correctly

2OS1 Access Control to Radiologically Significant Areas

CAP 032361

Root Cause Evaluation for CAP032361 -

Discrepant Dosimetry Results

January 27, 2003

CAP 032678

Locked High Radiation Area (LHRA) Locker Key

Found Unattended in the RP Office

December 28, 2002

CAP 034220

Adverse Trend in the Number of Electronic

Dosimeter Alarms during the Outage

March 19, 2003

CAP 034408

Worker Violated Locked High Radiation

Barricade

March 23, 2003

CAP 034460

HEPA Unit Found Unplugged

March 24, 2003

HP 2.5

Palisades Nuclear Plant Health Physics

Procedure - High Radiation Area Entry and

Control

Revision 20

HP 2.18

Palisades Nuclear Plant Health Physics

Procedure - Personnel Contamination

Revision 16

HP 2.20

Palisades Nuclear Plant Health Physics

Procedure - Radiation Safety Area Posting

Revision 15

HP 2.29

Palisades Nuclear Plant Health Physics

Procedure - Special Monitoring

Revision 9

HP 2.33

Palisades Nuclear Plant Health Physics

Procedure - Dose Investigation and Assessment

Revision 12

HP 2.33

Palisades Nuclear Plant Health Physics

Procedure - Dose Investigation and Assessment

Revision 12

HP 8.2

Palisades Nuclear Plant Health Physics

Procedure - Whole Body Count Evaluation

Revision 11

HP 11.2

Palisades Nuclear Plant Health Physics

Procedure - Control and Use of Portable

Ventilation

Revision 3

HP 11.4

Palisades Nuclear Plant Health Physics

Procedure - Evaluating Control of Airborne

Radioactivity and Respiratory Protection

Revision 4

HP 2.19

Palisades Nuclear Plant Health Physics

Procedure - Airborne Radioactivity Sampling

Revision 20

RWP P03-0007

Planning Inspections and Walkdowns

Revision 0

RWP P03-0501

Minor Activities in HRA

Revision 0

RWP P03-5004

Walkdowns and Inspections in Containment

Revision 3

2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls

ALARA Committee Meeting Minutes

March 27, 2003

ALARA In-Progress Review for RWP P03-5102,

Revision 1

March 23, 2003

ALARA In-Progress Review for RWP P03-5150,

Revision 0

March 24, 2003

AP 7.02

Palisades Nuclear Plant Administrative

Procedure - ALARA Program

Revision 11

AP 7.04

Palisades Nuclear Plant Administrative

Procedure - Radiation Dosimetry

Revision 19

AP 7.14

Palisades Nuclear Plant Administrative

Procedure - Temporary Shielding Program

Revision 9

CAP 034283

Three Individuals Receive Unnecessary Dose as

Work Had Already Been Completed

March 21, 2003

CAP 034284

Primary Coolant Activity Cleanup Did Not

Achieve Preoutage Agreed Upon Value

March 21, 2003

CAP 034336

Increased Personnel Dose Experienced Due to

Wrong Steam Generator Parts and Tool

March 22, 2003

HP 11.1

Palisades Nuclear Plant Health Physics

Procedure - Processing Radiation Work Permits

and ALARA Reviews

Revision 15

RWP P03-5100

Westinghouse Crane and Rigging Activities

Revision 1

RWP P03-5152

Installation and Removal of ROSA, ECT, and

Tube Plugging

Revision 5

RWP P03-5155

Secondary Side Steam Generator Inspection

Revision 7

RWP/ALARA Plan

P03-5102

Disassemble and Move Reactor Head to Stand

Revisions 0 - 1

RWP/ALARA Plan

P03-5108

Reactor Head Reassembly and Refueling Close-

Out Activities

Revision 0

RWP/ALARA Plan

P03-5111

Removal/Install ICI Flanges and Associated

Tasks

Revisions 0 - 1

RWP/ALARA Plan

P03-5150

Install and Remove Nozzle Dams in E-50A/B

Revision 0

RWP/ALARA Plan

P03-5306

Scaffold Work in Containment

Revisions 0 - 5

RWP/ALARA Plan

P03-5503

NDE Bare Metal Inspection on N-50 Reactor

Head

Revisions 0 - 1

3PP4

Physical Protection-Security Plan Change

Palisades Nuclear Plant Security Plan

Revision 47, Dated

January 10, 2003

4OA1 Performance Indicator Verification

Licensee Performance Indicator Data for Safety

System Functional Failures and Emergency

Diesel Generator Unavailability

January through

December 2002

4OA2 Identification and Resolution of Problems

Condition Reports Reviewed to Assess Condition Evaluation and Corrective Actions

CAP032269

Right Channel Monitor Line Caps Found

Removed During RT-71P

Condition Reports Reviewed to Assess Characterization of Identified Problems

CAP033879

NRC Annual Assessment Letter Notes CAP

Cross-Cutting Issue Still Open

CAP032785

Minor Error Noted in Condition Report Evaluation

CPAL02-01930

4OA3 Event Follow-up

Plant Procedures

GOP-14

Shutdown Cooling Operations

Revision 17

ONP-2.1

Loss of AC Power

Revision 12

ONP-17

Loss of Shutdown Cooling

Revision 28

EI-1

Emergency Classifications and Actions

Revision 41

Miscellaneous Documents

EA-CND-03-01

Past Operability Determination for Two Removed

Instrument Tube Caps on the Hydrogen

Monitoring System

Revision 0

LER 02-003

Licensee Event Report, Inoperable Containment

Hydrogen Monitors

February 19, 2003

LER 02-002

Licensee Event Report, Automatic Reactor Trip

and Safety System Actuation

January 21, 2003

LER 03-001

Licensee Event Report, Inoperable Steam

Generator Low-Level Channels

March 10, 2003

Technical Specification 3.3.1, Reactor Protective

System Instrumentation

Amendment 189

Condition Reports Reviewed To Assess Characterization of Identified Problems

CAP032931

Level Transmitter Static Pressure Effect not

Incorporated Correctly

CAP033022

Revision Required to January 17, 2003 Notice of

Enforcement Discretion (NOED)

Condition Reports Reviewed to Assess Root Cause Analysis and Corrective Actions

CAP033879

NRC Annual Assessment Letter Notes CAP

Cross-Cutting Issue Still Open

CAP032269

Root Cause Evaluation RCE 000314 for

CAP032269 Right Channel Monitor Line Caps

Found Removed During RT-71P

4OA5 Other

Miscellaneous Documents

Request for Enforcement Discretion - Steam

Generator Low-Level Setpoints

January 17, 2003

Request for Enforcement Discretion - Steam

Generator Low-Level Setpoints, Revision 1

January 22, 2003

NOED 03-3-001

Notice of Enforcement Discretion For Nuclear

Management Company LLC Regarding

Palisades

January 22, 2003

Technical Specification 3.0.3, Limiting Condition

for Operation Applicability

Amendment 189

Condition Reports Reviewed To Assess Problem Identification Characterization

CAP032943

Delay in Initiating Action Request for Steam

Generator Level Instrumentation