IR 05000266/2003009

IR 05000266-03-009, IR 05000301-03-009; on 10/01/2003 - 12/31/2003; for Point Beach, Units 1 & 2; Fire Protection, Maintenance Risk Assessment and Emergent Work Evaluation, Personnel Performance During Non-Routine Plant Evolutions and Event

ML040340170
Person / Time
Site:	Point Beach
Issue date:	01/30/2004
From:	Reynolds S Division Reactor Projects III
To:	Middlesworth G Nuclear Management Co
References
IR-03-009
Download: ML040340170 (97)

Text

ary 30, 2004

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000266/2003009; 05000301/2003009

Dear Mr. Van Middlesworth:

On December 31, 2003, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on January 6, 2004, with Mr. A. Cayia and members of his staff.

The inspection examined activities conducted under your license as they relate to safety and to 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.

Concurrent with this quarterly baseline inspection, the NRC completed an inspection in accordance with Inspection Procedure (IP) 95003, "Supplemental Inspection for Repetitive Degraded Cornerstones, Multiple Degraded Cornerstones, Multiple Yellow Inputs, or One Red Input." The IP 95003 supplemental inspection was conducted as a result of the Red finding related to the potential common mode failure of the auxiliary feedwater system, due to closure of the recirculation valve upon loss of instrument air. The results of the IP 95003 supplemental inspection are currently under review and will be documented in a separate inspection report.

In addition to the routine NRC inspection and assessment activities, and IP 95003 supplemental inspection activities, Point Beach performance is being evaluated quarterly as described in the May 9, 2003, Annual Assessment Follow-Up Letter - Point Beach Nuclear Plant. Consistent with Inspection Manual Chapter (IMC) 0305, plants in the multiple/repetitive degraded cornerstone column of the Action Matrix are given consideration at each quarterly performance

G. Van Middlesworth -2-assessment review for (1) declaring plant performance to be unacceptable in accordance with the guidance in IMC 0305; (2) transferring to the IMC 0350 "Oversight of Operating Reactor Facilities in a Shutdown Condition with Performance Problems" process; and (3) taking additional regulatory actions, as appropriate. On November 20, 2003, December 18, 2003, and January 15, 2004, the NRC reviewed Point Beach operational performance, inspection findings, and performance indicators for the fourth quarter of 2003. Based on this review, we concluded that Point Beach performance, while not clearly demonstrating improvements, did not represent unsafe operations. We determined that no additional regulatory actions, beyond the already increased actions and NRC management oversight, are currently warranted. However, we are concerned with the lack of indication that Point Beach performance is improving. As reflected in NRC-identified findings documented in this report regarding the control of combustible material and emergency preparedness training, your staff has failed to consistently demonstrate the ability to implement corrective actions in an effective and timely manner. In addition, several of the findings involve human performance issues where your staff failed to accomplish tasks in accordance with procedural guidance. We are concerned that the performance improvement initiatives implemented during the first half of 2003 have not been fully effective. The NRC will continue to closely monitor Point Beach performance consistent with the guidance in IMC 0305.

Based on the results of this inspection, three NRC-identified findings, three unresolved items, and three self-revealed findings of very low safety significance were identified, four of which involved violations of NRC requirements. However, because these violations were of very low safety significance and because the issues were entered into your corrective action program, the NRC is treating these four findings as Non-Cited Violations consistent with Section VI.A.1 of the NRC Enforcement Policy. Additionally, one licensee-identified violation is listed in Section 4OA7 of this report.

If you contest the subject or severity of a Non-Cited Violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, 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 Point Beach Nuclear Plant facility.

In accordance with 10 CFR 2.790 of the NRCs "Rules of Practice," a copy of this letter and its enclosure will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs

G. Van Middlesworth -3-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/

Steven A. Reynolds, Acting Director Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27

Enclosure:

Inspection Report 05000266/2003009; 05000301/2003009 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-266; 50-301 License Nos: DPR-24; DPR-27 Report No: 05000266/2003009; 05000301/2003009 Licensee: Nuclear Management Company, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: 6610 Nuclear Road Two Rivers, WI 54241 Dates: October 1 through December 31, 2003 Inspectors: P. Krohn, Senior Resident Inspector M. Morris, Resident Inspector J. Cameron, Project Engineer P. Higgins, Reactor Engineer D. Jones, Reactor Engineer R. Langstaff, Reactor Engineer T. Ploski, Senior Emergency Preparedness Inspector R. Schmitt, Radiation Specialist Observers: T. Bilik, Reactor Engineer K. Brock, Health Physicist, Office of Nuclear Reactor Regulation B. Jose, Reactor Engineer Approved by: A. Vegel, Chief Branch 7 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000266/2003009, 05000301/2003009; 10/1/2003 - 12/31/2003; Point Beach Nuclear

Plant, Units 1 & 2; Fire Protection, Maintenance Risk Assessment and Emergent Work Evaluation, Personnel Performance During Non-Routine Plant Evolutions and Events, Drill Evaluation, Access Control to Radiologically Significant Areas, Radioactive Material Control Program.

This report covers a 3-month period of baseline resident inspection and announced inservice (71111.08), emergency preparedness (71114), and radiation protection (71121) inspections for the Point Beach Nuclear Plant, Units 1 and 2. In addition, the inspectors completed two Temporary Instruction (TI) Inspections, TI 2515/150, Revision 2, Reactor Pressure Vessel Head and Vessel Head Penetration Nozzles, and TI 2515/152, RPV Lower Head Penetration (LHP) Nozzles (NRC Bulletin 2003-02). The announced inspections were conducted by three regional inspectors. Six Green findings associated with four non-cited violations (NCVs) were identified. The significance of most findings is indicated by their color (Green, White, Yellow,

Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 3, dated July 2000.

A. Inspector-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a Non-Cited Violation involving a finding of very low safety significance concerning the licensees failure to take effective corrective actions to address the control of transient combustibles. Specifically, the licensee failed to correctly determine the cause (i.e., transient combustibles) of exceeding an NRC Safety Evaluation Report fire loading value for a fire zone. As a result of ineffective corrective actions, the inspectors identified additional instances in which transient combustibles were not appropriately evaluated as required. The primary cause of this finding was related to the cross-cutting area of problem identification and resolution. Despite the escalation of fire loading issues by the licensees quality assurance organization in October 2002, combustible materials were reintroduced into the same fire zone without prior evaluation by November 2003.

This finding was more than minor because the finding, if uncorrected, could become a more significant safety concern and affect the Initiating Events cornerstone by increasing the likelihood or severity of fire. The finding was of very low safety significance because no fire protection features were affected and no instances were observed where the fire loading could cause either a fire barrier or an installed suppression system to be overwhelmed. This issue was a violation of a license condition which, by reference, invoked the licensees Fire Protection Evaluation Report (FPER), which required conditions adverse to fire protection, such as uncontrolled combustible material, be promptly identified, reported, and corrected. The FPER also required that in the case of significant or repetitive conditions adverse to fire protection, the cause of the conditions is to be determined and analyzed and prompt corrective actions taken to preclude recurrence. (Section 1R05.1.b.1)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low risk significance concerning an inadequate risk assessment associated with the 26th Unit 2 refueling outage (U2R26).

Specifically, personnel utilizing the core cooling key safety function shutdown risk assessment failed to recognize the unavailability and increased risk associated with removing the residual heat removal (RHR) pumps from the shutdown cooling mode of operation while in Mode 4, hot shutdown. The primary cause of this finding was related to the cross-cutting area of human performance in two respects. First, despite reviewing the activity prior to the outage, probabilistic risk assessment and outage planning personnel did not identify entry into the yellow risk category. Second, once relaxed, operations personnel did not increase the performance frequency of shutdown safety assessment checklists during periods of changing plant conditions, so as to have been able to identify the unavailability and increased risk associated with the activity.

The finding was considered more than minor because: (1) failure to recognize the increased risk condition resulted in compensatory risk management actions to protect the remaining reactor decay heat removal paths not being taken, actions intended to prevent entry into an unplanned orange or red risk condition; and (2) if left uncorrected, it would become a more safety significant concern, if elevated reactor decay heat removal risk categories were entered without the required risk management actions in place and subsequent heat removal challenges were to occur. The finding was of very low significance because it was not a design or qualification deficiency, did not represent an actual loss of the safety function, and did not involve internal or external initiating events. The finding was not a violation of regulatory requirements.

(Section 1R13.1)

Green.

A Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings, was self-revealed when inadequate procedure use resulted in starting a Unit 2 RHR pump with the suction valve shut. The primary cause of this finding was related to the cross-cutting area of human performance. Perceived time pressure, concurrent watch turnovers, lack of specific supervisory briefings, operator fatigue, and ineffective peer and self-checking resulted in a licensed senior reactor operator (SRO) and reactor operator not recognizing that the suction path to the B RHR pump was isolated prior to starting the pump.

This finding was considered more than minor because it: 1) affected the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events, and 2) involved the human performance attribute of the mitigating systems cornerstone. The finding was determined to be of very low risk significance since the inadequate procedure place keeping did not result in a design or qualification deficiency, an actual loss of safety function, or involve internal or external initiating events. (Section 1R14.1)

• To Be Determined. Unit 1. The inspectors identified an Unresolved Item (URI)concerning the installation of a non-safety related worm gear in the 1AF-4000, 1P-29 Auxiliary Feedwater (AFW) Pump Discharge to B Steam Generator, motor-operated valve. Initial hardness testing indicated that the 1AF-4000 worm gear had about one half of the material strength of the intended part. Material and fatigue property analyses to evaluate potential operability impacts had not been completed by the end of this inspection period. The issue did not represent an immediate safety concern since the non-conforming part was replaced with the appropriate safety-related part, and will be considered a URI pending completion of further regulatory review. (Section 1R15.2)

• To Be Determined. The inspectors identified an Unresolved Item (URI) concerning the licensees failure to install sprinklers in accordance with the applicable fire protection code in the component cooling water pump area. The safety significance of the issue is to be determined. The issue did not represent an immediate safety concern and will be considered a URI pending completion of further regulatory review. (Section 1R05.1.b.2)

Cornerstone: Barrier Integrity

• To Be Determined. Unit 1. The inspectors identified a URI concerning Framatome NCR [Non-Conformance Report] 6028873-Lack of ultrasonic testing (UT) coverage during Unit 1 refueling outage (U1R27) Reactor Pressure Vessel (RPV) Inspection.

The licensee contractor identified that, during the Unit 1 RPV head ultrasonic inspection in September 2002, stalling of the rotating ultrasonic probe head, due to coupling slippage, resulted in partial data acquisition in 10 of the 16 control rod drive mechanism (CRDM) nozzles.

This issue was documented in the licensees corrective action system as CA053202 and CE012362. Corrective actions to prevent recurrence (redesigned coupling, backup analysts) were implemented during the current Unit 2 outage. The licensee performed an analysis of the coverage limitations and determined that there was sufficient Unit 1 data for the testing results to remain valid. The licensee also planned to conduct an ultrasonic inspection of the CRDM nozzles during the next Unit 1 outage (U1R28). This issue will be a URI pending the inspectors review of the licensees analysis and results of the U1R28 nozzle examination. (Section 4OA5.1.c)

Cornerstone: Emergency Preparedness

Green.

The inspectors identified a finding of very low safety significance when they observed that the licensee failed to use the current revision to safety-related Emergency Plan Implementing Procedure (EPIP) 1.3, Tools for Dose Assessment, during a licensed operator requalification training class. This was the final scheduled class for this topic and the only one that was taught after the procedure had been revised on November 26, 2003. In addition, the inspectors noted that the training failed to include sheltering as a protective action recommendation option. This occurred despite the procedure having been changed the week before specifically to allow consideration of the sheltering option. The primary cause of this finding was related to the cross-cutting area of human performance in two respects. First, the decision not to train on the sheltering option represented a missed opportunity to train personnel on the full range of available protective action recommendations. Second, members of Operations management and Emergency Planning supervision failed to stop the training despite having been informed at the beginning of the class that the most current revision would not be used.

The finding was considered more than minor because it: (1) involved the emergency response organization readiness and response organization performance training attributes of the Reactor Safety/Emergency Preparedness cornerstone; and (2) if left uncorrected, it could lead to inadequate performance of protective action recommendations, actions intended to protect the health and safety of the public. The finding was not a violation of regulatory requirements. (Section 1EP6)

Cornerstone: Occupational Radiation Safety

Green.

A self-revealing finding of very low safety significance was identified involving a Non-Cited Violation of 10 CFR 20.1602 concerning the licensees failure to adequately control access to a Very High Radiation Area (VHRA). The licensee failed to guard the access to the Unit 2 Keyway (a posted VHRA) for approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> following identification by licensee personnel that the key to the Keyway lock had been lost (i.e., lack of positive control). The primary cause of this finding was related to the cross-cutting area of human performance, in that, despite adequate station procedures and training of radiation protection personnel for proper VHRA key control and requirements to post and guard VHRAs, the gate was left unguarded for several hours.

This issue was more than minor because both the VHRA key control issue, and the resulting unguarded VHRA gate issue, if left uncorrected, could become a more significant safety concern (i.e., had someone inadvertently accessed the Keyway, while the thimbles had been withdrawn). The finding was of very low safety significance, since the VHRA key was inaccessible to any plant personnel in the containment, as it had been inadvertently left in the pocket of protective clothing that had been transferred to an out-of-state laundry facility. Additionally, the Keyway access gate (which was locked and posted properly) was in the general proximity of a radiation protection work station, with radiation protection technicians generally present at that level of the reactor containment during the time period that the access was not positively controlled.

(Section 2OS1.4.b.1)

Cornerstone: Public Radiation Safety

Green.

A self-revealing finding of very low safety significance was identified involving a Non-Cited Violation of 10 CFR 20.1501 and 10 CFR 20.1802 concerning the licensees failure to adequately survey a valve prior to release from the restricted area and its subsequent shipment offsite to a vendor. Although the external surfaces of the valve were surveyed, the radiation protection technician performing the release survey was not aware that valve 2CV-203 had been exposed to primary reactor coolant and did not evaluate the possible internal contamination. During receipt surveys, the vendor identified the internal contamination prior to performing work on the valve. The primary cause of this finding was related to the cross-cutting area of human performance, in that, despite adequate station procedures and training of radiation protection personnel for proper determination of materials being evaluated for release or control at the Radiologically Controlled Area (RCA) boundary, an adequate survey was not performed and the valve was released for shipment to the vendor as unrestricted material.

This issue was more than minor because the radioactive material issue, if left uncorrected, could become a more significant safety concern. However, the finding was of very low safety significance since public radiation exposure was not greater than 0.005 Rem and the licensee did not have more than five radioactive material control occurrences in the previous eight quarters. (Section 2PS3)

Licensee-Identified Violations

Violations of very low significance, which were identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program (CAP). These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at full power and remained there for the duration of the assessment period, except for reductions in power to facilitate routine maintenance and testing.

In addition, on October 29 through 31, 2003, operators reduced power to 83 percent due to solar magnetic disturbances and the effect on electrical grid stability.

Unit 2 began the inspection period at 78 percent power during an end-of-cycle power reduction.

On October 3, 2003, operators began reducing power toward shutdown and the U2R26 outage began on October 4. Startup from the outage began on November 17. The Unit returned to full power operations on November 22 and remained there through the end of the assessment period, with the exception of brief power reductions to facilitate routine testing

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

a. Inspection Scope

The inspectors walked down accessible portions of risk-significant equipment and systems that were susceptible to cold weather freezing. The inspectors also reviewed the licensees preparation of the facade structures and buildings outside of the power block. The inspectors reviewed the corrective actions and work orders (WOs) written to correct problems that were identified and completion dates to ensure that work would be completed prior to the onset of cold weather. The inspectors also walked down areas that have had freeze problems during the last 4 years. These observations constituted two inspection samples, and included:

• Unit 1 cold weather preparations and facade freeze protection issues

• Unit 2 cold weather preparations and facade freeze protection issues

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed four partial walkdowns of accessible portions of risk-significant systems to verify the systems were capable of performing the intended function. The inspectors utilized valve and electrical breaker checklists, tank level books, plant drawings, and selected operating procedures to verify that the components were properly positioned and supported the systems as needed. The inspectors also examined the material condition of the components and observed operating equipment parameters to verify that there were no obvious deficiencies. The inspectors reviewed completed WOs and calibration records associated with the systems to verify that those documents did not reveal issues that could affect component or train function. The inspectors used the information in the appropriate sections of the Final Safety Analysis Report (FSAR) to determine the functional requirements of the system. These observations constituted four quarterly inspection samples.

The inspectors verified the alignment of the following systems:

• Unit 1 AFW Electrical Systems;

• Unit 2 AFW Electrical Systems;

• Unit 1 AFW Mechanical Systems; and

• Unit 2 AFW Mechanical Systems.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Walkdown of Selected Fire Zones

a. Inspection Scope

The inspectors performed fire protection walkdowns, which focused on availability, accessibility, and the condition of fire fighting equipment, the control of transient combustibles and ignition sources, and on the condition and operating status of installed fire barriers. The inspectors selected twelve fire areas for inspection based on their overall contribution to internal fire risk, as documented in the Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate a plant transient, or their impact on the plants ability to respond to a security event. The inspectors used the documents listed in the s to verify that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and that fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors verified that minor issues identified during the inspection were entered into the licensees CAP.

The following areas were inspected by walkdowns:

• Fire Area A19, D105 Battery Room Zone;

• Fire Area 142, Component Cooling Water (CCW) Pump Room;

• Fire Area 151, Safety Injection (SI) Pump Room;

• Fire Area 155, Valve Gallery - Pipe Way 1;

• Fire Area 156, MCC [Motor Control Center] Room - 1B32;

• Fire Area 159, HVAC [Heating, Ventilation and Air Conditioning] Equipment Room;

• Fire Area 162, Valve Gallery - Pipe Way 4;

• Fire Area 166, MCC Room - 2B32;

• Fire Area 187, Monitor Tank Room;

• Fire Area 225, Battery Room - D106;

• Fire Area 226, 125 Volts Direct Current (VDC) Electrical Equipment Room - D04; and

• Fire Area 227, 125 VDC Electrical Equipment Room - D03.

The inspectors review focused on the control of transient combustibles and ignition sources, the material condition of fire protection equipment, and the material condition and operational status of fire barriers used to prevent fire damage or propagation. Area conditions/configurations were evaluated based on information provided in the licensees Fire Hazards Analysis Report. The inspectors also walked down the listed areas to verify that fire hoses, sprinklers, and portable fire extinguishers were installed at their designated locations, were in satisfactory physical condition, and were unobstructed, and to verify the physical location and condition of fire detection devices.

Additionally, passive features such as fire doors, fire dampers, and mechanical and electrical penetration seals were inspected to verify that they were located in accordance with Fire Hazards Analysis Report requirements and were in acceptable physical condition. These observations constituted twelve quarterly inspection samples.

b. Findings

b.1 Inadequate Corrective Actions for Control of Transient Combustibles

Introduction:

The inspectors identified a finding involving the licensees failure to take adequate corrective actions to control transient combustible materials. This issue was determined to be of very low safety significance and was dispositioned as a Green Non-Cited Violation (NCV).

Description:

The inspectors observed materials in the 8 foot elevation of the primary auxiliary building which were not considered as part of the permanent fire loading calculations nor evaluated as transient combustible materials. Specifically, on October 16, 2003, the inspectors observed:

• In Fire Zone 159, HVAC equipment room, staging area having combustible materials including two coils of plastic hoses, storage barrel (55 gallon drum),plastic bucket, and an open large tool chest.

• Also in Fire Zone 159, several large storage cabinets, some of which were labeled as containing flammable materials.

• In Fire Zone 156, MCC room, anti-contamination clothing container and a large waste can; these materials were located approximately 10 feet below cable trays.

• In Fire Zone 142, CCW room, anti-contamination clothing container; the container was located approximately 7 feet below cable trays.

The inspectors were not able to locate a transient combustible control permit on any of the materials identified above. In addition, the inspectors reviewed the transient combustible material control log on October 16, 2003, and did not identify any permits which addressed these materials.

On November 13, 2003, the inspectors observed:

• In Fire Zone 159, HVAC equipment room, welding equipment, including electrical cables and rope.

• In Fire Zone 159, HVAC equipment room, staging area (same area as identified on October 16, 2003) with combustible materials including equipment cart with two coils of plastic hose and a coil of rubber hose, vacuum cleaner, and two canvas bags.

The inspectors did not observe any transient combustible control permits on the materials identified above. In addition, on November 13, 2003, the inspectors identified two large metal cabinets in Fire Zone 187, monitor tank room, containing binders of procedures and plastic hoses, plastic sheets, paper office supplies, and plastic bottles.

Based on discussions with the licensees on-site fire protection engineer and review of informal calculations which had been performed by the engineer, the metal cabinets had been added since the engineer had evaluated the fire loading in the area on October 3, 2002. The engineer stated that his understanding was that the paper (binders of procedures) had been relocated from a nearby operator workstation to the metal cabinet and had been previously evaluated as part of his fire loading calculations for the area.

However, the other materials had not been evaluated by the licensees fire protection engineer. The inspectors were not able to identify any administrative controls which limited the amount of material or the type of material placed in the cabinets.

The inspectors reviewed the calculation for fire loading (Calculation 2002-0039) and noted that the materials identified on October 16, 2003, and November 13, 2003, were not considered in the fire loading for the applicable fire zones. The inspectors reviewed the licensees procedure for transient combustible control, Nuclear Plant Procedure (NP)

NP 1.9.9, Transient Combustible Control. The inspectors noted that Section 2.1 of the procedure stated that small amounts of combustible materials used for normal plant operation (rubber hose, protective clothing, radiation protection materials, reference materials, ladders, stools, etc.) were considered part of the permanent fire load. The inspectors expressed concern that licensee personnel could apply the above statement to mean that combustible materials used for normal plant operation had been considered as part of the permanent fire load and did not need to be evaluated as a transient combustible. However, based on review of Calculation 2002-0039, the inspectors determined that only minimal quantities of such materials, if at all, were considered as part of the permanent fire loading calculations.

The inspectors determined that the licensee had previously identified concerns with respect to fire loading calculations and materials not considered as part of fire loading calculations. The licensees review of fire loading issues was a result of an audit (Audit Report A-P-01-19) by the licensees quality assurance organization. The licensee had specifically identified (as documented by condition report CAP003279) that the fire loading in one fire zone (Fire Zone 187) had exceeded the fire loading value described in an NRC Safety Evaluation Report (SER) for the zone (transmitted by letter dated July 3, 1985). The licensee attributed the cause (as documented by apparent cause evaluation ACE000757) for exceeding the fire loading value to be due to ordinary combustibles located in the area, including an operator work station. However, the licensee failed to identify the lack of administrative controls as a cause for exceeding the SER fire loading value. The inspectors noted that corrective actions for the fire loading in Fire Zone 187 were delayed and the quality assurance organization became involved by addressing the issue with the site vice-president (letter NPM 2002-0521). By October 3, 2002, the licensee had reduced the amount of materials in the area such that the area fire loading was within the SER value. However, as discussed above, additional materials were later introduced to the area which had not been evaluated.

Analysis:

The inspectors identified a performance deficiency, in that the licensee failed to take effective corrective actions to address control of transient combustibles. The inspectors determined that continued failure to adequately evaluate and control combustible materials could lead to the fire loading exceeding the amount considered by the NRC as part of the licensing basis. In accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, issued on June 20, 2003, the inspectors determined that the issue was more than minor because the finding, if uncorrected, could become a more significant safety concern. In accordance with IMC 0609, Appendix A, the inspectors performed a SDP Phase 1 screening and determined that the finding affected the Initiating Events cornerstone by increasing the likelihood or severity of fire. The inspectors determined that the finding was of very low safety significance (Green) because no fire protection features were affected and no instances were observed where the fire loading could cause either a fire barrier or an installed suppression system to be overwhelmed.

Enforcement:

License condition 3.H requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR for the facility. Section 9.10.1 of the FSAR states, in part, that the fire protection program is outlined in the FPER. Section 3.1.2.2 of the FPER states, in part, that an administrative procedure is maintained to provide guidelines for the appropriate handling and use of transient combustible material within the plant. This procedure is based on the guidance of National Fire Protection Association standards, evaluation of the level of hazard, and an evaluation of the level of protection in specific areas. This is done for both in situ and transient combustible loading. The procedure addresses the storage and handling of combustible materials associated with plant operation and maintenance, flammable and combustible liquids, wood, and plastic (including temporary storage). Section 4.8 of the FPER states, in part, that measures are established to ensure that conditions adverse to fire protection such as failures, malfunctions, deficiencies, deviations, defective components, uncontrolled combustible material, and non-conformances are promptly identified, reported, and corrected as required by the CAP. Section 4.8 of the FPER also stated that in the case of significant or repetitive conditions adverse to fire protection, including fire incidents, the cause of the conditions is determined and analyzed and prompt corrective actions are taken to preclude recurrence. The cause of the condition and the corrective action taken are to be promptly reported to cognizant levels of management for review and assessment.

Contrary to this:

• As of November 14, 2003, the licensee failed to correctly determine the cause of exceeding the SER fire loading value in Fire Zone 187, in that administrative controls for combustibles were not addressed and that the requirements of FPER Section 3.1.2.2 were not met; and

• On October 16, 2003, and November 13, 2003, the licensee failed to ensure that combustible materials were adequately controlled, in that combustible materials were identified which were neither evaluated as part of the permanent fire loading calculations nor were evaluated as transient combustibles as required by FPER Section 3.1.2.2.

The licensees failure to take adequate corrective actions, as described above, is a violation of license condition 3.H. This violation is associated with a finding that is characterized by the SDP as having very low risk significance (Green) and is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. This violation was entered into the licensees corrective action program as CAP051177, CAP051838, and CAP051870 (NCV 05000266/2003009-02; 05000301/2003009-02).

b.2 Sprinkler Head Locations Not In Accordance With Fire Code

Introduction:

The inspectors identified that the licensee failed to install sprinklers in accordance with the applicable fire protection code in the CCW pump area. The safety significance of the issue is to be determined and the issue will be treated as a URI pending further NRC review of significance determination.

Description:

On October 16, 2003, the inspectors identified that a number of the ceiling sprinkler heads in the CCW pump area (Fire Zone 142) were located at an excessive distance down from the ceiling. The specific observations included that:

(1) a sidewall sprinkler located along the north wall of the CCW pump area was approximately 18 inches below the ceiling;

(2) two ceiling sprinkler heads in the central part of the CCW pump area above the CCW pumps were located approximately 24 inches below the ceiling; and

(3) three sprinkler heads along the east wall were located more than 24 inches below the ceiling. The sprinkler system was a wet pipe sprinkler system and was required to satisfy the automatic suppression requirements of 10 CFR Part 50, Appendix R, Section III.G.2. The inspectors noted that the ceiling in the CCW pump area was smooth and composed of concrete. Section 4-3.1.1 of the applicable fire protection code for sprinklers, NFPA [National Fire Protection Association] 13-1978, specified that deflectors of sprinklers in bays be located 1 inch to 12 inches below noncombustible smooth ceilings.

The inspectors determined that the licensee had previously identified NFPA code violations concerning the installed sprinkler system on the 8 foot elevation of the primary auxiliary building, the same building and elevation as the CCW pump area. The specific issue identified was that the minimum spacing between sprinkler heads had not been maintained. The inspectors reviewed the corrective action document generated at the time, CAP000769, and noted that one of the recommendations was to perform a walkdown of the sprinkler systems to determine all code violations. Based on discussions with the licensees on-site fire protection engineer, the inspectors concluded that although a walkdown of the sprinkler system had been performed, the walkdown was ineffective, as evidenced by the licensees failure to identify the finding that the sprinkler were not properly located.

Analysis:

In accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, issued on June 20, 2003, the inspectors determined that the issue was more than minor because the finding was associated with the protection against external factors (i.e., fire) attribute of the Mitigating Systems reactor safety cornerstone and affected the Mitigating Systems objective in that a fire protection feature (i.e., an automatic suppression system) was adversely affected. In accordance with IMC 0609, Appendix A, the inspectors performed an SDP Phase 1 screening and determined that the finding degraded the Fire Protection portion of the Mitigation Systems Cornerstone. As such, screening under IMC 0609, Appendix F, was required.

Based on review of IMC 0609, Appendix F, the inspectors determined that the finding required a Phase 2 evaluation since a fire protection feature was affected. The nonconforming location of the sprinkler heads would result in delay in activation of the sprinkler system because it would take a deeper (i.e., increased distance from the ceiling) hot gas layer to activate individual sprinkler heads. As such, the inspectors considered the sprinkler system in the CCW pump area to be degraded. The licensee presented initial information concerning the ignition frequencies for the area and what mitigating equipment would be available in the event of a fire. However, the inspectors determined that additional information would be required to assess the issue under IMC 0609, Appendix F.

Enforcement:

License condition 3.H requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR for the facility. Section 9.10.1 of the FSAR states, in part, that the fire protection program is outlined in the FPER. Section 6.3.1 of the FPER stated, in part, that NFPA 13 provided dimensional guidance and criteria necessary for installation or evaluation of an existing water suppression system. Section 6.3.3 of the FPER stated, in part, that fixed water extinguishing systems were designed and installed in accordance with applicable portions of NFPA 13 and NFPA 15. Section 4-3.1.1 of NFPA 13-1978, specified that deflectors of sprinklers in bays shall be located 1 inch to 12 inches below noncombustible smooth ceilings. Contrary to the above, as of October 16, 2003, the inspectors identified six ceiling level sprinkler heads in the CCW pump area which were located in excess of 12 inches below the ceiling. The licensees failure to install a sprinkler system in accordance with NFPA 13, as described above, is a violation of license condition 3.H. This issue was entered into the licensees corrective action program as CAP051175. This issue will be considered a URI pending additional engineering review and review of additional information to be provided by the licensee (URI 05000266/2003009-03; 05000301/2003009-03).

1R06 Flood Protection Measures

a. Inspection Scope

During the week of November 3, 2003, the inspectors completed one internal flood protection inspection sample by walking down the Unit 1 & 2 Facade Flood Zones to assess the overall readiness of internal flood protection equipment and barriers.

The inspectors evaluated flood protection features, such as flood doors, door gaps, and subsoil drains to verify that they were in satisfactory physical condition, unobstructed, and capable of providing an adequate flood barrier. The inspectors also reviewed design basis documents and risk analyses.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

.1 Resident Inspector Review of Heat Sink Performance

a. Inspection Scope

During the week of October 13, 2003, the inspectors reviewed documents associated with performance testing of spent fuel pool heat exchangers, HX-13A and B, to evaluate thermal performance capabilities and the licensee's corrective action for heat exchanger performance testing and cleaning. The inspectors reviewed the test preparations, system lineups, instrumentation configuration, test performance, and test results for engineering rigor and completeness. The inspectors also interviewed the licensee vendor conducting the test to evaluate vendor experience, verify coordination with Point Beach personnel, and ensure that appropriate acceptance criteria were clearly specified.

The inspectors reviewed the test protocol documentation to confirm that the test or inspection methodology was consistent with accepted industry and scientific practices.

This observation constituted one inspection sample.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection (ISI) Activities

a. Inspection Scope

The inspectors reviewed the implementation of the licensees ISI program for monitoring degradation of the reactor coolant system (RCS) boundary and the risk significant piping system boundaries. Specifically, the inspectors reviewed records of the following four nondestructive examination activities to evaluate compliance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements and to verify that indications and defects were dispositioned in accordance with the ASME Code:

• Visual examination of the Unit 2 RPV lower head penetration (bottom mounted instrumentation) Nozzles: 8, 17, 26, and 35;

• Ultrasonic examination of Unit 2 SI system weld 11 (SIS-10-SI-2002-11);

• Ultrasonic examination of Unit 2 SI system weld 14 (AC-10-SI-2001-14); and

• Ultrasonic examination of Unit 2 SI system weld 15 (AC-10-SI-2001-15).

These observations constituted two quarterly inspection samples.

The inspectors also reviewed the radiographic examination of a pressurizer spray nozzle safe-end to nozzle weld (indications found to be acceptable per ASME IWB 3514-2)from the previous outage with recordable indications that have been accepted by the licensee for continued service to verify that the acceptance was in accordance with the ASME Code. This review counted as one inspection sample.

The inspectors attempted to review pressure boundary welds for Class 1 or 2 systems which were completed since the beginning of the previous refueling outage, to verify that the welding acceptance (e.g., radiography) and preservice examinations were performed in accordance with ASME Code requirements. However, the licensee had not performed any such welds, therefore, no samples could be selected.

The inspectors reviewed one ASME Section XI Code replacement, involving the removal and replacement of a Code Class 1, Unit 2 RCS valve and section of pipe (WO 0206367) to verify that the replacement met ASME Code requirements. This review counted as one inspection sample.

The inspectors reviewed a sample of ISI related problems documented in the licensees CAP to assess conformance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. In addition, the inspectors verified that the licensee correctly assessed operating experience for applicability to the ISI group.

The inspectors also confirmed that the steam generator (SG) tube eddy current examination (ECT) scope and expansion criteria met Technical Specification (TS)requirements, Electrical Power Research Institute (EPRI) Guidelines, and commitments made to the NRC; confirmed that all areas of potential degradation (based on site-specific experience and industry experience) were inspected, especially areas which are known to represent potential ECT challenges (e.g., top-of-tubesheet, tube support plates, U-bends); confirmed that the ECT probes and equipment were qualified for the expected types of tube degradation; assessed the site specific qualification of one or more techniques (e.g., equipment, data quality/noise issues, degradation mode);assessed corrective actions for loose parts or foreign material discovered on the secondary side of the SG; and reviewed the following eddy current data because questions arose regarding eddy current data analyses:

• SG 21, row 72, column 73; and

• SG 21, row 44, column 79 This review counted as one inspection sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

On December 8, 2003, the inspectors observed an operating crew during a licensed operator requalification training exercise using Emergency Plan Implementing Procedure (EPIP) 10.1, Emergency Reentry, Revision 22. The inspectors also reviewed some of the changes to the simulator model against modifications made in the plant. This observation constituted one quarterly inspection sample.

The inspectors evaluated crew performance in the areas of:

• clarity and formality of communications;

• understanding of the interactions and function of the operating crew during an emergency;

• prioritization, interpretation, and verification of actions required for personnel movement once emergency response facilities have been activated;

• procedure use during an emergency;

• equipment operations staff will use in the facilities during an emergency;

• oversight and direction from supervisors; and

• group dynamics.

The inspectors compared crew performance in these areas to licensee management expectations and guidelines as presented in NP 2.1.1, Conduct of Operations, Revision 1. The inspectors verified that the crew completed the critical tasks listed in the emergency facility position guide.

b. Findings

No findings of significance were identified.

1R12 Maintenance Rule (MR) Implementation

a. Inspection Scope

The inspectors reviewed the implementation of two MR systems to verify that component and equipment failures were identified, entered, and scoped within the MR and that selected systems, structures, and components were properly categorized and classified as (a)(1) or (a)(2) in accordance with 10 CFR 50.65. The inspectors reviewed station logs, maintenance WOs, action requests, (a)(1) corrective action plans, functional failures, unavailability records, selected surveillance test procedures, and a sample of CAP documents to verify that the licensee was identifying issues related to the MR at an appropriate threshold and that corrective actions were appropriate. The inspectors also walked down portions of systems to examine material condition, ensure the proper implementation of action plans, and to verify that past functional failures had been corrected. The inspectors reviewed the licensees performance criteria to verify that the criteria adequately reflected equipment performance needs and to verify that licensee changes to performance criteria were reflected in the licensees probabilistic risk assessment. These observations constituted two quarterly inspection samples.

Specific components and systems reviewed were:

• Facade Freeze Protection; and

• Structures.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessment (RA) and Emergent Work Evaluation

.1 Inadequate RA Associated With Removing RHR Pumps From The Shutdown Cooling

Mode Of Operation

a. Inspection Scope

During the weeks of November 10 and 24, 2003, the inspectors reviewed the licensees evaluation of plant risk during U2R26 refueling outage restart efforts to determine if scheduled and emergent work activities had been adequately managed. In particular, the inspectors reviewed the activities associated with transitioning the Unit 2 A and B RHR pumps, 2P-10A and 2P-10B, from the shutdown cooling to the SI mode of operation while in Mode 4, hot shutdown. The inspectors focused on the adequacy of the pre-outage 10 CFR 50.65(a)(4) RA and operations performance of shutdown safety assessment checklists to evaluate the adequacy of the licensees shutdown risk planning and use of risk management tools. In addition, the inspectors interviewed selected operations and probabilistic RA personnel and reviewed selected WOs to determine whether, on November 9, the appropriate risk categories had been entered, whether the licensee had implemented normal work controls or risk management actions (RMAs) in accordance with NP 10.3.6, Outage Safety Review and Safety Assessment, and whether key safety functions had been preserved. This observation constituted one quarterly inspection sample.

b. Findings

Introduction.

The inspectors identified a Green finding concerning an inadequate shutdown RA which failed to recognize the unavailability of the Unit 2 RHR pumps and the increased risk associated with their removal from the shutdown cooling mode of operation while in Mode 4, hot shutdown, on November 9, 2003.

Description.

During control board walkdowns on the morning of November 10, 2003, the inspectors identified that the 2P-10A and 2P-10B RHR pumps had been removed from the shutdown cooling mode of operation and placed in the SI configuration over the previous night shift. The activity had been accomplished in accordance with Operating Procedure (OP) 7B, Removing Residual Heat Removal System From Operation, in preparation for transitioning Unit 2 from Mode 4, hot shutdown, to Mode 3, hot standby.

Referencing the most current shutdown safety assessment checklist that the shift technical advisor had completed on November 9 at 2:30 p.m., the inspectors discovered that on the morning of November 10, 2003 the licensee was still taking credit for two trains of RHR being available in the core cooling key safety function area despite RHR shutdown cooling operations having been secured on November 9, 2003. The inspectors questioned the shift technical advisor who performed another shutdown safety assessment checklist on November 10, 2003, at 9:00 a.m. This RA verified that the core cooling key safety function had been in the licensee-defined yellow risk category during the previous night.

The inspectors determined that the RHR pumps had been unavailable for the core cooling function between the time the control switches had been taken to pullout (approximately 5:25 p.m.) and the time the transition to the SI mode of operation had been completed (11:40 p.m.), a period of 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and 15 minutes. In addition, the inspectors noted that on the morning of November 7, 2003 performance of the shutdown safety assessment checklist had been relaxed from once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to once per day as permitted by licensee Procedure NP 10.3.6, Step 5.4.1. The result of this decision was that a shutdown safety assessment checklist was not completed prior to removing the RHR pumps from the shutdown cooling mode of operation on the evening of November 9, 2003, an action, had it been performed, would have afforded the opportunity to identify the yellow core cooling risk category that subsequently occurred between 5:25 and 11:40 p.m. The licensee did not resume increased performance of the checklist once Unit 2 plant conditions and configurations began to change on November 9. Finally, the inspectors determined that although the pre-outage RA had considered performance of OP 7B, the assessment had not recognized the unavailability of the RHR pumps to perform the core cooling key safety function when transitioning between the shutdown cooling and SI modes of operation as performed in OP 7B, Steps 5.3 through 5.29.

Licensee Procedure NP 10.3.6, Steps 3.7.1 and 5.5, defined several RMAs to be performed for yellow risk categories. The RMAs included identifying equipment as protected so as to create a heightened awareness to maintain the availability of remaining or redundant equipment; prohibiting work on protected equipment; prominently identifying protected equipment or areas containing protected equipment with printed signs; maintaining updated shutdown safety assessment status boards at strategic locations throughout the plant; including a list of protected equipment on the shutdown safety assessment status boards; communicating the status of key safety functions to the work control center and the shift outage manager for each performance of the shutdown safety assessment checklist; and identifying equipment as protected during operations shift turnovers and plan-of-the-day meetings. Without having identified the core cooling yellow risk condition associated with removing the RHR pumps from the shutdown cooling mode of operation, appropriate RMAs as described in NP 10.3.6 were not implemented on November 9 between 5:25 and 11:40 p.m.

Analysis.

The inspectors determined that not implementing RMAs normally required for a yellow shutdown risk condition was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, issued on June 20, 2003. The inspectors determined that the issue was more than minor because:

(1) failure to recognize the increased risk condition resulted in compensatory risk management actions to protect the remaining reactor decay heat removal paths not being taken, actions intended to prevent entry into an unplanned orange or red risk condition; and

(2) if left uncorrected, it would become a more safety significant concern if elevated reactor decay heat removal risk categories were entered without the required RMAs in place and subsequent heat removal challenges were to occur. Also, the inspectors determined that not implementing RMAs normally required for a yellow shutdown risk condition affected the cross-cutting area of human performance in two respects. First, despite reviewing the activity prior to the outage, probabilistic RA and outage planning personnel did not identify entry into the yellow risk category. Second, operations personnel did not recognize the need to increase the performance frequency of shutdown safety assessment checklists during periods of changing plant conditions.

The inspectors completed a significance determination of the issue using IMC 0609, Significance Determination Process, dated March 21, 2003, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, dated March 18, 2002. The inspectors determined that the finding was not a design or qualification deficiency, did not represent an actual loss of the safety function, and did not involve internal or external initiating events. Therefore, the finding was considered to be of very low safety significance (Green).

Enforcement.

Because transitioning the RHR pumps from the shutdown cooling to the SI mode of operation was associated with a plant configuration change completed for the purposes of normal plant operations rather than a maintenance activity, no violation of regulatory requirements occurred. This issue was considered a finding (FIN) of very low safety significance (FIN 05000301/2003009-04). The licensee entered the issue into its corrective action system as CAP051696, PBF [Point Beach Form]-1562 SD

[Shutdown] Safety Assessment Not Filled Out In A Timely Manner.

.2 Risk Review of Selected Work Week Activities

a. Inspection Scope

The inspectors reviewed the licensees evaluation of plant risk, scheduling, configuration control, and performance of maintenance associated with planned and emergent work activities to verify that scheduled and emergent work activities were adequately managed. These observations constituted six quarterly inspection samples.

In particular, the inspectors reviewed the following specific activities:

• October 6, 2003. This week was the beginning of the Unit 2 refueling outage.

The work included shutdown and cooldown of the Unit.

• October 13, 2003. The work included core offload and effects of schedule delays on the risk profile.

• October 20, 2003. This week included the core reload and mid loop operations.

• November 2, 2003. This week included several outage extensions and the beginning of normal work week activities that were scheduled following the outage.

• November 24, 2003. This week included routine and post-outage activities.

• December 1, 2003. This week included routine work and switchyard relay testing by an off-site organization.

b. Findings

No findings of significance were identified.

1R14 Personnel Performance During Non-Routine Plant Evolutions and Events

.1 Operator Error Results In Starting a RHR Pump With the Suction Valve Shut

a. Inspection Scope

During the weeks of October 20, 2003 and November 17, 2003, the inspectors reviewed the circumstances associated with starting the Unit 2 B RHR pump, 2P-10B, on October 19, 2003, with the suction valve shut. The inspectors reviewed the existing plant configuration at the time of the event as well as the human performance, communications, procedure use and adherence, and shift management command and control aspects of the event to determine if operator actions had been conducted in accordance with the licensees policies, procedures, and expectations. This observation constituted one inspection sample.

b. Findings

Introduction:

A Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed when inadequate procedure place keeping resulted in starting a RHR pump with the suction valve shut. This issue was considered to be self-revealing because the isolated suction source was promptly indicated by an unexpected system response and rapidly decreasing RHR pump discharge flows.

Description:

During the Unit 2 U2R26 refueling outage the reactor core had been fully off-loaded to the spent fuel pool. Prior to core reload the operators recognized the need to add borated water to the refueling cavity to achieve the proper level required for commencement of refueling activities. On October 18, 2003, operators transferred boric acid and reactor makeup water to the Unit 2 refueling water storage tank (RWST) to achieve the proper boric acid concentration needed for addition of inventory to the refueling cavity. Operators determined that the best method of mixing the RWST contents was to pump the RWST to the reactor cavity and then pump the cavity back to the RWST to obtain a uniform boron concentration within the refueling pool and both A and B RHR trains.

The operators utilized safety-related Refueling Procedure RP 1C, Refueling, Revision 49 to perform the transfers. The operators utilized RP 1C, Step 5.12, for the first transfer of the RWST contents to the refueling cavity. Since the A RHR pump, 2P-10A, was used for the transfer, the A RHR pump suction valve from the RWST, 2SI-856A, was opened. In accordance with Step 5.12.2.b, the B RHR pump suction valve from the RWST, 2SI-856B, was shut since the B pump was not being used during the initial transfer. The operators proceeded to use RP 1C, Step 5.13, to perform the second transfer of the refueling cavity contents back to the RWST to continue with the mixing evolution. This second transfer from the cavity to the RWST occurred using both the A and B RHR pumps. Once the required water was transferred to the RWST, the B RHR pump was secured at 6:04 a.m. on October 19, 2003, and the A RHR pump left running. Shortly after securing the B RHR pump, SRO shift turnover commenced. At 6:22 a.m., with A RHR pump still running, RP 1C Step 5.12 was repeated to commence pumping down the RWST to the refueling cavity. Using RP 1C, F, and with the intent of starting the B RHR pump and securing the A RHR pump to equalize the boron concentration in both trains of RHR, the B RHR pump was started at 6:29 a.m. Over the next 70 seconds, operators noticed abnormal flow indications in that the B RHR pump discharge flow had decreased unexpectedly.

Investigation revealed that the B RHR pump suction valve from the RWST, 2SI-856B, had been shut.

The inspectors identified a procedure use error, in that during the first transfer of RWST contents to the refueling cavity in accordance with RP 1C, Step 5.12.2.b, had directed the opening of only one of the RWST to RHR pump suction valves. Since operators had used the A RHR pump for the initial transfer, 2SI-856A was opened and 2SI-856B was shut. The operators failed to recognize this initial configuration when starting the B RHR pump in accordance with RP 1C, Attachment F, Step 5.12, a location in the procedure remote form the initial record of only 2SI-856A having been opened. Failing to reference the first performance of Step 5.12 in the main body of the procedure when starting the B RHR pump resulted in the operators not realizing the suction valve to the B RHR pump, 2SI-856B, had remained shut.

Analysis:

The inspectors determined that starting an RHR pump with the suction valve isolated was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on June 20, 2003. The inspectors determined that the finding was more than minor because it: 1) affected the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events, and 2) involved the human performance attribute of the mitigating systems cornerstone. The inspectors determined that the issue also affected the cross-cutting area of human performance because perceived time pressure, concurrent watch turnovers, lack of specific supervisory briefings, operator fatigue, and ineffective peer and self-checking contributed to a licensed SRO and reactor operator not recognizing that the suction path to the RHR pump was isolated prior to starting the pump. The inspectors determined that since a recirculation line from the B RHR pump discharge to the pump suction had been in service when the pump was started with the suction valve shut, subsequent engineering evaluations and inspections determined that the pump had not been damaged, and operators had reacted to promptly secure the pump when abnormal flow indications were noticed, the operability of the RHR pump had not been adversely impacted.

The inspectors completed a significance determination of this issue using IMC 0609, Significance Determination Process, dated March 21, 2003, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, dated March 18, 2002. The inspectors determined that the finding did not result in a design or qualification deficiency, an actual loss of safety function, or involve internal or external initiating events. Therefore, the finding was considered to be of very low safety significance (Green).

Enforcement:

Appendix B, Criterion V, of 10 CFR Part 50, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, on October 19, 2003, during attempts to equalize boron concentrations in the Unit 2 RHR trains, inadequate procedure use associated with Refueling Procedure RP 1C, Steps 5.12 and 5.13, Revision 49, resulted in starting the Unit 2 2P-10B RHR pump with the suction path isolated.

This violation was entered into the licensee's corrective action system as CAP051222, Unit 2 RHR Pump Started On Mini-Recirculation Versus RWST. Because this violation was of very low safety significance and it was entered into the licensees CAP, this violation is being treated as an NCV consistent with Section VI.A. of the NRC Enforcement Policy. (NCV 05000301/2003009-05)

.2 Low Instrument Air (IA) Header Pressure

a. Inspection Scope

On December 5, 2003, the inspectors observed the response to a low North IA header pressure alarm when an unsoldered pipe joint separated causing the air header pressure to drop to approximately 50 pounds. The inspectors reviewed the resulting Unit 2 plant transient which included complete closure of one main feedwater regulating valve, partial closure of the other regulating valve, and reduced steam generator levels.

The inspectors reviewed control room operator action to start the back-up air compressor, operate the main feedwater regulating valves in manual, stabilized the plant, and returned Unit 2 to normal operations. The inspectors also reviewed the timeliness and assessment capabilities of a relief operator who responded to the announcement about low IA header pressure, heard the air venting, followed the sound to the lower level of the North service building, located the break, traced the air line to the nearest isolation valve, and stopped the leak. This observation constituted one inspection sample.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Unit 1 and 2 Containment Purge Supply and Exhaust Isolation Valve Boot Seals

a. Inspection Scope

During the weeks of November 4, 2003, and 17, 2003, the inspectors reviewed Operability Determination OPR000093, Unit 1 and Unit 2 Containment Purge, Supply and Exhaust System Supply (VNPSE-3244, -3245) and Exhaust (VNPSE-3212, -3213),

Revisions 0 and 1 and CAP051581, VNPSE [Ventilation Purge Supply and Exhaust]

Valves IST [Inservice Inspection Test] Acceptance Criteria Incorrect Not Conservative, to determine the potential primary containment integrity impacts of relaxed T-ring seals.

The inspectors interviewed selected engineering personnel, reviewed past seal leakage data and design basis requirements, evaluated the effects of limited instrument air supplies on Large-Early-Release-Frequency (LERF) risk parameters, and reviewed selected emergency and abnormal operating procedures to determine the ability of the purge supply and exhaust valves to perform the intended safety function. This observation constituted one inspection sample.

b. Findings

The purge supply and exhaust system was used to purge containment atmosphere prior to personnel entry following reactor shutdown. The containment isolation valves associated with this system were normally maintained closed with their control switches locked in the closed position in Modes 1, 2, 3, and 4 to ensure containment boundary integrity was maintained. There were four valves associated with each Unit, two associated with the supply system and two associated with the exhaust system. For each penetration, one valve was located inside containment and one outside containment. Each valve was a 36" diameter butterfly valve that used an elastomer T-ring at the seating surface to achieve a tight seal. The IA system supplied external pressure to the T-ring which forced the ring against the butterfly disc periphery. Without the pneumatic pressure, there was no contact between the valve disc and the T-ring.

All purge supply and exhaust valves had an air accumulator which, in case of IA failure, retained air pressure to the T-ring. In addition to the air accumulators, the Unit 2 VNPSE valves outside containment were equipped with a safety-related nitrogen backup system. Inservice test procedures measured T-ring seal air supply system leakage for each purge supply and exhaust valve with an IA pressure drop acceptance criteria of 5 pounds per square inch gauge/hour. Using abnormal operating Procedure 5B and the vendor recommended minimum pressure to ensure proper operation of the T-ring seal, the seals would be below minimum pressure in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and containment integrity challenges could occur. Since the licensing basis duration for maintaining containment integrity was 30 days, operator action to re-align the IA system or change nitrogen bottles for Unit 2, would be required to assure that the minimum boot seal pressure would be maintained for the full 30 days, actions not specifically described or discussed in the FSAR and plant design basis.

Since the IA system was not safety-related and could not be relied upon to mitigate the consequences of an accident, the licensee determined that the containment isolation function was non-conforming to the licensing basis. Although the IA system was not safety-related, it was considered reliable in that the system; 1) was restored early in the emergency operating procedures following a design basis loss-of-coolant accident; 2) observed simulator scenarios had demonstrated that operators would restore IA in approximately 30 minutes; 3) the IA system was supplied with an automatic back-up source of pressure from the service air system; and 4) the IA compressors are powered from the safeguard busses. Based on these attributes, the licensee determined that there was sufficient time to restore the IA system and normal operating pressure to the T-ring seals such that containment integrity would not be challenged.

The inspectors determined that the licensee had not fully understood the primary containment design basis in that the safety-related function of maintaining containment integrity for 30 days following a design basis loss-of-coolant accident had been dependent on a non-safety related system, instrument air. The licensee did not recognize the vulnerability of the instrument air dependency on the boot seal performance and verify that sufficient actions were in place to restore IA prior to containment integrity challenges until VNPSE butterfly valve testing that occurred during the Unit 2 refueling outage. The inspectors determined that leakage of two valves in series could pose a challenge to containment integrity during a design basis accident involving loss of IA and relaxed boot seals. The inspectors reviewed boot seal leakage data from 2000 to the present and identified that between August 14, and October 12, 2002, for the Unit 1 purge exhaust penetration and between May 5 and June 5, 2002, for the Unit 2 supply penetration such a condition had existed.

The inspectors determined that the issue of containment integrity, being dependent on a non-safety system, IA, to perform the intended safety function was more than minor since it affected the reactor safety/barrier integrity cornerstone containment functionality attributes of 1) design control, operational capability; 2) configuration control, preservation of containment boundaries, and 3) barrier performance, containment isolation reliability and availability. The inspectors determined that the issue did not affect core damage frequency but influenced containment LERF.

The Regional Senior Reactor Analyst reviewed the issue for potential LERF significance using MC 0609, Appendix H and NUREG-1765, Basis Document for Large Early Release Frequency (LERF) Significance Determination Process (SDP). The issue was determined to be a Type B finding, in that it was unrelated to those structures, systems, and components that are needed to prevent accidents from leading to core damage but had a potentially important implication for the integrity of the containment.

NUREG-1765 states that a containment leak rate of about 100 volume percent per day for PWRs appears to constitute an approximate threshold beyond which the release may become significant to LERF. The 100 volume percent per day leakage rate is approximately equivalent to a hole size in containment of 2.5 - 3.0 inches in diameter for Point Beachs large dry containment. The containment purge valve leakage (approximate leakage of a 1/16 inch gap) would represent an area less than that of a 2.5 in diameter hole; and would therefore not be considered a LERF concern. This issue is considered to screen out as an issue of green risk significance using MC 0609, Appendix H. This licensee-identified violation is dispositioned in Section 4OA7.

.2 Non-Safety Related Worm and Worm Gears Used in Safety-Related Motor Operated

Valve (MOV) Actuators

a. Inspection Scope

During the weeks of November 8 and December 15, 2003, the inspectors reviewed Operability Determination OPR000092, Non-QA [Quality Assurance] Worm Used in QA MOV for 1SI-866A, and CAP051530, Non-QA Worm and Worm Gear Used in QA Application for Limitorque Operator SMB-00, to determine the operability effects of non-safety related parts on six safety-related MOVs. The inspectors interviewed selected engineering personnel and reviewed vendor material strength calculations; MOV force loading calculations; design basis requirements; extent-of-condition assessments; and selected valve actuator timing trends to evaluate the ability of the MOVs to perform the intended safety function. This observation constituted one inspection sample.

b. Findings

During Unit 2 refueling outage work on a turbine-driven AFW pump steam supply MOV, maintenance personnel identified that a non-safety related worm gear had been installed in the actuator during the last refurbishment. A licensee work history search revealed that six other MOVs also contained varying combinations of non-safety worms and worm gears, four Unit 2 MOVs and two Unit 1 MOVs. The Unit 2 non-safety related components were all replaced with safety-related parts during the refueling outage prior to power ascension. One Unit 1 MOV, 1SI-866A, Cold Leg Injection Line Isolation, remained installed with an operable but non-conforming designation with the justification that, although testing and certification requirements differed, both the safety-related and non-safety related parts had been manufactured by the same original equipment manufacturer (OEM) and had identical design and manufacturing requirements. Hence, the strength and endurance properties of both the safety-related and non-safety related parts were reasoned to be the same and the ability to perform the intended safety-related function was determined to be unaffected. Since the four Unit 2 MOVs had used OEM components, the same argument applied to past operability considerations for those MOVs.

The remaining Unit 1 MOV, 1AF-4000, 1P-29 Auxiliary Feedwater Pump Discharge to B Steam Generator, was declared inoperable at 3:05 p.m. on October 31, 2003, since the installed worm gear had not been manufactured by the original equipment manufacturer and the same argument could not be applied. A safety-related worm gear was subsequently installed and the limiting condition for operation exited at 4:27 p.m. on November 1, 2003. Initial hardness testing indicated that the 1AF-4000 worm gear had about one half of the material strength of the OEM part.

Since an analysis of 1AF-4000 material and fatigue properties had not been finished at the end of this inspection period, the safety significance of the issue is To Be Determined. The issue did not represent an immediate safety concern and will be considered a URI pending completion of further regulatory review (URI 05000266/2003009-06). The licensee entered this condition as CAP051530, Non QA Worm and Worm Gear Used in Quality Assurance Application for Limitorque Operator SMB-00.

.3 Through-Wall Pinhole Leak in Service Water (SW) Suction Piping to the 2P-29 AFW

Pump

a. Inspection Scope

During the weeks of November 10 and 24, 2003, the inspectors reviewed the operability determination and initial operator actions associated with CAP051703, Through-Wall Pinhole Type Leak in Service Water Piping to 2P-29 Auxiliary Feedwater Pump, to evaluate the impact of the leak on AFW system operability. The inspectors interviewed selected system engineering and nondestructive evaluation personnel, reviewed the adequacy of SW piping monitoring programs, verified the adequacy of the leak isolation boundaries, reviewed ASME Code classification and NRC guidance concerning evaluation and repair of the piping, evaluated licensed operator understanding and awareness of evaluation requirements and operability bases, and reviewed the timeliness with which operations personnel isolated the pinhole leak to ensure the AFW system remained capable of performing the intended safety function. This observation constituted one inspection sample.

b. Findings

No findings of significance were identified.

.4 Selected Operability Determination Reviews

a. Inspection Scope

The inspectors reviewed three operability determinations the licensee generated that warranted selection on the basis of risk. The inspectors reviewed the following operability determinations:

• prompt operability determination for CAP050815, FI-4007, P-38A AFW Pump Exhibited Intermittent Flow Indication With P-38B Running, October 8, 2003;

• Operability Determination 000096, Main Steam Containment Penetrations, November 17, 2003; and

• prompt operability determination for CAP051234, Unknown Auxiliary Feedwater Indication Has Been Found, October 19, 2003.

The inspectors assessed the accuracy of the evaluations, the use and control of compensatory measures as needed, and compliance with the TSs. The inspectors review included a verification that the operability determinations were made as specified by NP 5.3.7, Operability Determinations. The technical adequacy of the determinations were reviewed and compared to the TSs, Technical Requirements Manual, Updated Safety Analysis Report (USAR), and associated design basis documents. In addition, the inspectors reviewed selected issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance. This observation constituted three inspection samples.

b. Findings

No findings of significance were identified.

1R16 Operator Workarounds (OWAs)

a. Inspection Scope

The inspectors reviewed operator workarounds with particular focus on the method by which instructions and contingency actions were communicated and reviewed to on-shift licensed operators.

The inspectors completed three samples by reviewing:

• Electrical power configuration during the Unit 2 refueling outage to accommodate work on three switchyard transformers;

• OWA 0-03-001 FP, Fireworks Fire Detection System; and

• OWA 0-03R-002 RMS, SPING detector alarms due to low background radiation.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (PMT)

a. Inspection Scope

The inspectors reviewed PMT activities associated with the scheduled and emergent work activities listed below to verify that the testing was adequate for the scope of the work performed and the equipment remained capable of performing the intended function. These observations constituted seven quarterly inspection samples.

The inspectors reviewed the following activities:

• PMT on the 2MS-2019 steam supply valve to the Unit 2 turbine-driven AFW pump;

• PMT on 1AF-4000 following worm replacement;

• PMT for Containment Isolation Valve 2SC-966A, after rework for leakage;

• PMT for CCW Pump 1P-11A, after quarterly motor greasing and bearing oil flushing and change;

• PMT for Crossover Steam Dump Valve 1-DV-1, after troubleshooting failure of valve to reseat during a quarterly surveillance test;

• PMT for the Unit 2 main steam dump valve for B steam generator, 2-MS-2015, following outage maintenance; and

• PMT for containment spray system suction valves following routine maintenance.

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities

.1 Routine Refueling Outage Inspection Activities

a. Inspection Scope

The inspectors observed the licensees performance during the twenty-sixth Unit 2 refueling outage (U2R26) conducted between October 4 and November 17, 2003.

These inspection activities constitute one refueling outage inspection sample.

This inspection consisted of a in-office review of the licensees outage schedule, safe shutdown plan and administrative procedures governing the outage, periodic observations of equipment alignment, and plant and control room outage activities.

Specifically, the inspectors assessed the licensees ability to effectively manage elements of shutdown risk pertaining to reactivity control, decay heat removal, inventory control, electrical power control, and containment integrity.

The inspectors conducted in-plant observations of the following daily outage activities:

• attended outage management turnover meetings to verify that the current shutdown risk status was accurate, well understood, and adequately communicated;

• performed walkdowns of the main control room to observe the alignment of systems important to shutdown risk;

• observed the operability of RCS instrumentation and compared channels and trains against one another;

• performed in-plant walkdowns to observe ongoing work activities; and

• conducted in-office reviews of selected issues that the licensee entered into its corrective action program to verify that identified problems were being entered into the program with the appropriate characterization and significance.

Additionally, the inspectors performed in-plant observations of the following specific activities:

• control room staff performing the Unit 2 shutdown and initial cooldown;

• that RCS cooldown rates were within TS limits;

• control room staff operations during reduced inventory conditions;

• RPV head lift;

• core unloading activities in the reactor containment, spent fuel pool, and control room;

• core reload from the control room;

• core load verification from containment;

• operators aligning the RHR system for shutdown cooling;

• placement of the over-pressure protection system into operation;

• a pre-job briefing for fuel handling evolutions;

• walkdowns of the auxiliary building to verify the placement of clearance orders on the Unit 2 electrical bus, Units 1 and 2 CCW, and the Unit 2 SW systems;

• lifting and transport of the reactor vessel head in preparation for core offload;

• alignment of the spent fuel pool cooling systems;

• walkdown of the control room and turbine building to verify Unit 2 safety-related electrical alignments following battery charger and 4 kilo-volt electrical bus routine maintenance;

• closeout inspection of the Unit 2 containment, including a review of the results of the emergency core cooling sump inspection that had been performed earlier by the licensee. As part of this inspection, the inspectors also verified that all discrepancies noted during the walkdown were recorded and corrected;

• portions of low power physics testing and initial dilution to criticality;

• portions of the plant power ascension;

• reviewed Mode change checklists and verified that selected requirements were met while transitioning from the refueling Mode to full power operations;

• walked down nozzle dam control panels to verify proper indications, installation, removal, and alarms functions;

• steam generator drain plug removal and boroscope inspection for debris in drain hole;

• review of shutdown margin calculations;

• spent fuel pool cooling and SW pump configurations during full core offload;

• inspected and verified reduced inventory level RCS transmitter configurations;

• verified proper alignment and operation of potential-dilution-in-progress alarm; and

• reviewed the evaluation of thimble tube fine debris in new fuel assemblies.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed selected surveillance tests and reviewed test data to verify that risk-significant equipment met the TS, FSAR, and licensee procedural requirements and demonstrated the capability to perform the intended safety functions. The activities were selected based on their importance in verifying mitigating systems capability and barrier integrity. The inspectors used the documents listed in the Attachment to verify that the testing met frequency requirements; that the tests were conducted in accordance with the procedures, including establishing the proper plant conditions and prerequisites; that the test acceptance criteria were met; and that the results of the tests were properly reviewed and recorded. In addition, the inspectors interviewed operations, maintenance and engineering department personnel regarding the tests and test results. These observations constituted eight quarterly observations.

The inspectors completed the following samples by evaluating the following surveillance tests:

• Inservice Test (IT) 545C, Leakage Reduction and Preventative Maintenance Program Test of Containment Spray System Mode 1, 2, or 3, Unit 2;

• IT-65, Containment Isolation Valves Quarterly Test;

• Operations Refueling Test (ORT) 64, RE 211 and 212 Supply Leak Rate Test;

• ORT 3A, Safety Injection Actuation With Loss Of Engineering Safeguards AC, Unit 2 (Trains A&B);

• Unit 1 Containment Tendon Gallery 15 Year ISI;

• IT-4D, Unit 2 Residual Heat Removal Valve Exercise Test for Operations or Shutdown Unit;

• IT 245, Safety Injection Accumulator Valves (Cold Shutdown) Unit 2; and

• ORT 3B, Safety Injection Actuation With Loss Of Engineering Safeguards AC, Unit 2 (Trains A&B).

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors conducted in-plant observations of the physical changes to the equipment and in-office reviews of documentation associated with two temporary modifications. The inspectors reviewed design basis documents and safety evaluation screenings to ensure that the modifications were consistent with documents, drawings and procedures. The inspectors also reviewed the post-installation results to confirm that any impacts of the temporary modifications on permanent and interfacing systems were adequately verified. These observations constituted two inspection samples.

The inspectors reviewed the following temporary modifications:

• Unit 2 Primary Containment Purge Supply and Exhaust System Blank Flange Installation; and

• Unit 2 Steam Generator Nozzle Dam Installation During Refueling Outage.

b. Findings

No findings of significance were identified.

1EP2 Alert and Notification System (ANS) Testing

a. Inspection Scope

The inspector discussed with Emergency Preparedness staff the operation, maintenance, and periodic testing of the ANS in the Manitowoc County portion of the Point Beach Nuclear Plants Emergency Planning Zone (EPZ). The discussions were to determine whether this ANS equipment was adequately maintained by Wisconsin Public Service Company staff, who remained responsible for the maintenance of the Point Beach Nuclear Plants and the Kewaunee Nuclear Power Plants ANS equipment for these plants overlapping EPZs. The inspector reviewed and discussed the results of periodic ANS tests performed by Manitowoc County officials for the time period from January 2002 through October 2003. The inspector observed a member of the licensees emergency plan staff while she coordinated with a county official, who initiated a weekly test of the 14 ANS sirens within Manitowoc County. The inspector also reviewed samples of 2002 and 2003 records associated with scheduled and other ANS equipment maintenance activities for the Manitowoc County sirens to verify that adequate corrective actions were taken following test failures and other identified equipment malfunctions. These activities constituted one inspection sample.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization (ERO) Augmentation Testing

a. Inspection Scope

The inspector reviewed and discussed aspects of the licensees provisions for augmenting its onshift ERO, besides those documented in Supplemental Inspection Report 50-266/02-14 and 50-301/02-14 and Supplemental Inspection Report 50-266/03-06 and 50-301/03-06.

Specifically, the inspector reviewed and discussed with emergency plan staff the procedures that included the primary and alternate methods of initiating an ERO activation to augment the onshift ERO, plus provisions for maintaining the ERO call-out roster and for periodically updating the ERO Telephone Directory. The inspector also reviewed critique and CAP records of extra staff augmentation drills that were conducted in Summer 2003 to determine the adequacy of the drills critiques and associated corrective actions. The inspector observed a portion of an emergency plan overview training course, which was attended by a group of ERO members, to assess the adequacy of the courses information on the licensees emergency planning commitments, including its onshift ERO augmentation provisions. These activities constituted one inspection sample.

b. Findings

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspector reviewed Letters of Agreement, which were maintained onsite, with the offsite support organizations listed in Revisions 21 and 22 of Appendix D of the Emergency Plan to determine whether any changes in any agreement may have decreased the effectiveness of the licensees emergency planning. The inspector also reviewed the following May 2003 revisions to portions of the Emergency Plan to determine whether any changes reduced the effectiveness of the Plan: Section 1, Section 2, Section 8, and Appendix A. The inspector noted that the May 2003 revisions to Appendices E, F, and G of the Plan were basically references to the States and counties emergency plans that were maintained separately by offsite officials. The inspector also noted that the draft Revision 23 to Appendix D included an existing Letter of Agreement that was not listed in the previous two revisions of this Appendix. These activities constituted one inspection sample.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed a sample of Nuclear Oversight staffs 2002 and 2003 audits of the emergency plan program to verify that these independent assessments met the requirements of 10CFR 50.54(t). The inspector also reviewed a sample of critiques and corrective action documents that were associated with the 2002 biennial exercise, as well as various emergency plan drills conducted in 2002 and 2003 in order to verify that the licensee fulfilled its drill commitments and to evaluate the licensees efforts to identify, track, and resolve concerns identified during these activities. The inspector reviewed and discussed recent records associated with the ongoing project to reassess and upgrade the plants meteorological monitoring equipment. These activities constituted one inspection sample.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

.1 Protective Action Recommendation Training for Licensed Reactor Operators Using an

Outdated Procedure

a. Inspection Scope

The inspectors observed the classroom and laboratory protective action recommendation training for licensed operators during the week of December 4, 2003.

The training consisted of a classroom discussion of EPIP 1.3, Dose Assessment and Protective Action Recommendations Revision 31, and a laboratory section that included several dose assessments and required the operators to make recommendations. The inspectors also reviewed the adequacy of the training associated with EPIP 1.3, Revision 32. The inspection activity constitutes one inspection sample.

b. Findings

Introduction:

A Green finding was identified when the inspectors observed that the licensee failed to use a current revision to EPIP 1.3, a safety related procedure, during a licensed operator requalification training class. The finding was not considered a violation of regulatory requirements.

Description:

On December 4, 2003, during the Tools for Dose Assessment class the instructor did not use the current revision of EPIP 1.3, Dose Assessment and Protective Action Recommendations, Revision 32. This was the final scheduled class for this topic and the only one that was taught after the procedure had been revised on November 26, 2003. The instructor stated at the beginning of class that the procedure had been changed and that he was using the old revision. The instructors rational was that the class objectives were not to train on the specific changes on Revision 32, thus using the previous revision remained acceptable. The inspectors noted that the training failed to include and detail sheltering as an option. This occurred despite the procedure allowing such consideration having been changed the week before. Operators were being trained to an outdated, superceded procedure.

The Assistant Operations Manager, Operations Training Shift Manager, two Shift Managers, and an Emergency Preparedness Supervisor in the classroom recognized that training was being performed from an old revision. However, they did not stop the training and have the instructor obtain the most current revision. They did discuss the need for the current revision during the break between the classroom portion and the practical application portion of the class. The inspector observed the class to see if the new revision of the procedure was brought into the room where the practical application was taught. The inspector noted that the new revision was not used by the students nor was there any mention about the changes during the practical application exercises.

The trainees that stayed after the class were given the new revision of the procedure.

The procedure change discussing the addition of sheltering as an option did not occur until after an e-mail was sent to those that were required to perform dose assessment.

The inspectors questioned the emergency plan Supervisor on the effectiveness of the training and whether there has been any follow-up effectiveness review.

Analysis:

The inspectors determined that providing training on the wrong revision of the EPIP was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued on June 20, 2003. The finding was considered more than minor because it:

(1) involved the emergency response organization readiness and response organization performance training attributes of the Reactor Safety/Emergency Preparedness cornerstone; and

(2) if left uncorrected, it could lead to inadequate performance of protective action recommendations, actions intended to protect the health and safety of the public. Also, the inspectors determined that not training on the change to the procedure (the inclusion of sheltering as an option for the protective action recommendation) affected the cross-cutting area of human performance in two respects. First, the decision not to train on the sheltering option represented a missed opportunity to train personnel on the full range of available protective action recommendations. Second, the Assistant Operations Manager, Operations Training Shift Manager, two Shift Managers, and an Emergency Preparedness Supervisor in the classroom failed to stop the training despite having been informed at the beginning of the class that the most current revision would not be used.

The inspectors completed a significance determination of the issue using IMC 0609, Significance Determination Process, dated March 21, 2003, Appendix B, Emergency Preparedness Significance Determination Process, dated March 3, 2003. The inspectors determined that the finding was considered to be of very low safety significance (Green).

Enforcement:

The operators were being trained on activities in accordance with a safety-related procedure. The procedure was one required by 10 CFR 50.47(b)(5), and the training was required by 10 CFR 50.47(b)(15). Because the correct revision of the procedures was in the emergency response facilities and the training that was presented did not include any portion of the procedure that had been changed, no violation of regulatory requirements occurred. This issue was considered a finding of very low safety significance (FIN 05000266/2003009-07; 05000301/2003009-07). The licensee entered the event into its corrective action system as CAP052133, Failure to Use Current Copy of Procedure in Classroom Training, dated December 4,

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Review of Licensee Performance Indicator (PI) for the Occupational Exposure

Cornerstone

a. Inspection Scope

The inspectors reviewed the licensees occupational exposure control cornerstone PIs to determine whether the conditions surrounding the PIs had been evaluated, and that identified problems had been entered into the CAP for resolution. This represents one sample completed.

b. Findings

No findings of significance were identified.

.2 Plant Walkdowns and Radiation Work Permit (RWP) Reviews

a. Inspection Scope

The inspectors reviewed licensee controls and surveys in the following radiologically significant work areas within radiation areas and high radiation areas (HRAs) in the plant and reviewed work packages which included associated licensee controls and surveys of these areas to determine if radiological controls including surveys, postings and barricades were acceptable:

• Radwaste handling areas;

• Primary Auxiliary Building (PAB);

• Refuel floor/Spent fuel pool area; and

• Unit 2 Containment.

The above inspection activity constitutes one inspection sample.

The inspectors walked down and surveyed (using an NRC survey meter) the above four areas to verify that the prescribed radiological work permit (RWP), procedure, and engineering controls were in place, that licensee surveys and postings were complete and accurate, and that air samplers were properly located. The inspection activity constitutes one inspection sample.

The inspectors reviewed the RWPs and work packages used to access the above four areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. The inspectors evaluated electronic dosimeter alarm set points for both integrated dose and dose rate for conformity with survey indications and plant policy. The inspectors interviewed workers to verify that they were aware of the actions required when their electronic dosimeters noticeably malfunctioned or alarmed. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.3 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed five corrective action reports related to access controls and two high radiation area (HRA) radiological incidents when available (non-PIs identified by the licensee in HRAs <1R/hr). The inspectors interviewed staff members and reviewed corrective action documents to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

• Evaluation of safety significance/risk and priority for resolution;

• Identification of repetitive problems;

• Identification of contributing causes;

• Identification and implementation of effective corrective actions;

• Resolution of NCVs tracked in the corrective action system; and

• Implementation/consideration of risk significant operational experience feedback.

The above inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.4 High Risk Significant, High Dose Rate HRA and VHRA Controls

a. Inspection Scope

The inspectors discussed with Radiation protection supervisors the controls that were in place for special areas that had the potential to become very high radiation areas (VHRAs) during certain plant operations (i.e., spent fuel movements), to determine whether the operations required communication beforehand with the Radiation protection group, so as to allow corresponding timely actions to properly post and control the radiation hazards. The inspection activity constitutes one inspection sample.

The inspectors walked down applicable areas of the plant to verify the posting and locking of entrances to high dose rate HRAs, and VHRAs. The inspection activity constitutes one inspection sample.

b. Findings

b.1 Failure to Control Access to a Very High Radiation Area

Introduction:

The inspectors identified a NCV of 10 CFR 20.1602 of very low safety significance (Green), which was identified through a self-revealing event, when the key for the Unit 2 Keyway (i.e., a posted VHRA, which had been established prior to withdrawing the thimbles ) was uncontrolled, and, subsequently, the access to the Keyway was improperly controlled for approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. Despite adequate station procedures and training of Radiation protection personnel for the proper control of VHRA keys and posted VHRAs, the Keyway access was improperly controlled by the licensee.

Description:

On October 9, 2003, a radiation protection technician (RPT) locked and posted the Unit 2 Keyway as a VHRA. This was in preparation for withdrawing the thimbles into the Keyway. The key, which was required to be administratively controlled at all times for the VHRA lock, was left in the protective clothing that had been worn during the close-out tour of the Keyway. The protective clothing was then deposited in the used clothing bags. The key would have normally been stored in the Field Operations VHRA lock box. Licensee personnel discovered that the key was missing approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> later. The licensees immediate actions included the installation of another VHRA lock on the access to the Unit 2 Keyway and to contact the laundry vendor. The inspectors determined that the Keyway access was not immediately guarded between the time when licensee personnel discovered the key to be missing and the time that the new VHRA lock was installed. Additionally, during the period that the access was not properly guarded, the thimbles had been withdrawn into the Keyway.

The event was self-revealing when the RPT realized that the key was not being properly controlled (i.e., under administrative control, in the Field Operations VHRA key locker).

Analysis:

The inspectors determined that the issue was associated with the Program and Process and Human Performance attributes of the Occupational Radiation Safety Cornerstone and affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material. The cornerstone objective was affected because both cases (the VHRA key control issue and the resulting unguarded VHRA gate issue) could, if left uncorrected, have become a more significant safety concern if someone inadvertently accessed the Keyway while the thimbles had been withdrawn. Therefore, the issue was considered to be more than minor.

The inspectors determined that the RPTs failure to properly control the VHRA key and then the subsequent failure of the licensee to post guards at the Keyway access during the time the key was improperly controlled constituted a violation of station procedures and personnel training requirements. The inspectors evaluated the finding using IMC 0609, Appendix C, Occupational Radiation Safety SDP. Since the finding did not involve as low as is reasonably achievable (ALARA)/work controls; did not result in an overexposure, nor was there a substantial potential for an overexposure; and the licensees ability to assess dose was not compromised, the inspectors concluded that the finding was of very low safety significance (Green).

Enforcement:

Title 10 CFR 20.1602 requires, in part, that in addition to the requirements of 10 CFR 20.1601 (i.e., control of access to HRAs) that licensees institute additional measures to ensure that an individual is not able to gain unauthorized or inadvertent access to areas in which radiation levels could be encountered at 500 rads or more in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at one meter. The licensees failure to guard the access to the Keyway during the period when licensee personnel recognized that the VHRA key was missing and the new lock was applied to the Keyway access is a violation of 10 CFR 20.1602. The licensee entered the issue into its corrective action program (CAP050962). Because this violation was of very low safety significance and it was entered into the licensees CAP, this violation is being treated as an NCV consistent with Section VI.A. of the NRC Enforcement Policy. (NCV 05000301/2003009-08).

2OS2 ALARA Planning And Controls (71121.02)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed plant collective exposure history, current exposure trends, ongoing and planned activities in order to assess current performance and exposure challenges. This included determining the plants current 3-year rolling average for collective exposure in order to help establish resource allocations and to provide a perspective of significance for any resulting inspection finding assessment. The inspection activity constitutes one inspection sample.

The inspectors reviewed the outage work scheduled during the inspection period and associated work activity exposure estimates for the following five work activities which were likely to result in the highest personnel collective exposures:

• UT inspection under reactor head;

• Reactor vessel bottom mounted instrumentation inspection;

• Install/Remove scaffolding;

• SG eddy current testing (ECT); and

• Remove/Replace SG Handhole covers, Sludge lance and foreign object search and retrieval inspections.

The above inspection activity constitutes one inspection sample.

The inspectors determined site specific trends in collective exposures and source-term measurements. The inspection activity constitutes one inspection sample.

The inspectors reviewed procedures associated with maintaining occupational exposures ALARA and processes used to estimate and track work activity specific exposures. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.2 Radiological Work Planning

a. Inspection Scope

The inspectors evaluated the licensees list of work activities, ranked by estimated exposure, that were in progress and reviewed the following five work activities of highest exposure significance:

• UT inspection under reactor head;

• Reactor vessel bottom mounted instrumentation inspection;

• Install/Remove scaffolding;

• SG ECT; and

• Remove/Replace SG Handhole covers, Sludge lance and foreign object search and retrieval inspections.

The above inspection activity constitutes one inspection sample.

For these five activities, the inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements in order to verify that the licensee had established procedures, and engineering and work controls that were based on sound Radiation protection principles in order to achieve occupational exposures that were ALARA. This also involved verifying that the licensee had grouped the radiological work into reasonable work activities, based on historical precedence, industry norms, and/or special circumstances. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.3 Verification of Dose Estimates and Exposure Tracking Systems

a. Inspection Scope

The inspectors reviewed the assumptions and bases for the current annual collective dose estimate, including procedures used, to evaluate the licensees methodology for estimating work activity-specific exposures and the intended dose outcome. The inspectors evaluated the dose rate and man-hour estimates for accuracy. The inspection activity constitutes one inspection sample.

The inspectors evaluated the licensees process for adjusting exposure estimates or re-planning work due to unexpected changes in scope, emergent work or higher than anticipated radiation levels. This included verifying that adjustments to estimated exposure (intended dose) were based on sound Radiation protection and ALARA principles and not adjusted to account for failures to control the work. The inspectors reviewed the frequency of these adjustments to evaluate the adequacy of the original ALARA planning process. The inspection activity constitutes one inspection sample.

The inspectors evaluated the licensees exposure tracking system to determine whether the level of exposure tracking detail, exposure report timeliness, and exposure report distribution was sufficient to support control of collective exposures. The inspectors reviewed radiation work permits to determine if they covered a manageable number of work activities to allow work activity-specific exposure trends to be detected and controlled. During the conduct of exposure significant work, the inspectors evaluated whether licensee management maintained awareness of the collective dose associated with the work and would intervene if dose trends increased beyond the original estimates. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.4 Job Site Inspections and ALARA Control

a. Inspection Scope

The inspectors observed the following three jobs that were being performed in radiation areas, airborne radioactivity areas, or HRAs for observation of work activities that presented the greatest radiological risk to workers:

• Destructive removal of reactor head O rings;

• Dispositioning of Tri-Nuke filters (from reactor cavity pool to Radwaste area); and

• Reactor re-assembly/Refuel floor activities.

The above inspection activity constitutes one inspection sample.

For these work activities, the inspectors evaluated the licensees use of ALARA controls.

The inspectors evaluated engineering controls to achieve dose reductions to verify that procedures and controls were consistent with the licensees ALARA reviews, that adequate shielding of radiation sources was provided, and that the dose expended to install/remove the shielding did not exceed the dose reduction benefits afforded by the shielding. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.5 Source-Term Reduction and Control

a. Inspection Scope

The inspectors reviewed licensee records to determine the historical trends and current status of tracked plant source terms and to determine if the licensee was making allowances and had developed contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.6 Radiation Worker Performance

a. Inspection Scope

The inspectors observed radiation worker and RPT performance during work activities performed in radiation areas, airborne radioactivity areas, and HRAs that presented the most significant potential for radiological risk to workers. The inspectors evaluated whether workers demonstrated adherence to the ALARA philosophy in practice by their familiarity with the work activity scope and tools to be used, by utilizing low dose waiting areas, and by implementing prescribed work activity controls. Also, the inspectors reviewed radiation worker training and skill levels to determine whether they were sufficient relative to the radiological hazards and the work involved. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.7 Declared Pregnant Workers

a. Inspection Scope

The inspectors reviewed dose records of a declared pregnant worker for the current assessment period to verify that the exposure results and monitoring controls employed by the licensee complied with the requirements of 10 CFR Part 20. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.8 Problem Identification and Resolutions

a. Inspection Scope

The inspectors reviewed the licensees self-assessments, audits, and Special Reports related to the ALARA program since the last inspection to determine if the licensees overall audit programs scope and frequency for all applicable areas under the Occupational Cornerstone met the requirements of 10CFR 20.1101(c). The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

.1 Rescue Capabilities During Use of One-Piece Atmosphere Supplying Respiratory

Protection Devices

a. Inspection Scope

The inspectors evaluated the licensees respiratory protection program and the use of respiratory protection equipment to limit the intake of radioactive material. The inspectors examined the licensees procedures, lesson plans, and related respiratory protection qualification training materials and discussed their implementation relative to the requirements of 10 CFR 20.1703(f) for standby rescue persons whenever one-piece atmosphere supplying suits, or any combination of respiratory protection and personnel protective equipment were used, in which the wearer may have difficulty removing.

Specifically, the inspectors reviewed the licensees work planning process and implementing practices, and interviewed Radiation protection staff and a member of the licensees confined space rescue team regarding the following aspects of 10 CFR 20.1703(f):

• designation of an adequate number of standby rescue workers and their training/instruction;

• presence of equipment staged at the work site for the safety of the rescuer and for extrication of the respiratory equipment user;

• practices for continuous communication between standby rescuer(s) and the respiratory protection user(s); and

• provisions for immediate availability of the standby rescuer.

The inspectors interviewed Radiation protection management regarding their proposal for enhancing the RWP and ALARA planning processes and for developing safety plans for those jobs (i.e., not performed in confined space atmospheres, but where limiting the intake of radioactive materials is desirable) to formally address work provisions for standby rescuers.

b. Findings

No findings of significance were identified.

Cornerstone: Public Radiation Safety

2PS2 Radioactive Material Processing and Transportation (71122.02)

.1 Radioactive Waste System

a. Inspection Scope

The inspectors reviewed the liquid and solid radioactive waste system description in the USAR for information on the types and amounts of radioactive waste (radwaste)generated and disposed. The inspectors reviewed the scope of the licensees audit program with regard to radioactive material processing and transportation programs to verify that it met the requirements of 10 CFR 20.1101(c). The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.2 Radioactive Waste System Walkdowns

a. Inspection Scope

The inspectors walked down the liquid and solid radwaste processing systems to verify that the systems agreed with the descriptions in the USAR and the Process Control Program, and to assess the material condition and operability of the systems. The inspectors reviewed the status of radioactive waste process equipment that was not operational and/or was abandoned in place. The inspectors reviewed the licensees administrative and physical controls to ensure that the equipment would not contribute to an unmonitored release path or be a source of unnecessary personnel exposure.

The inspectors reviewed changes to the waste processing system to verify that the changes were reviewed and documented in accordance with 10 CFR 50.59 and to assess the impact of the changes on radiation dose to members of the public. The inspectors reviewed the current processes for transferring waste resin into shipping containers to determine if appropriate waste stream mixing and/or sampling procedures were utilized. The inspectors also reviewed the methodologies for waste concentration averaging to determine if representative samples of the waste product were provided for the purposes of waste classification in 10 CFR 61.55. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.3 Waste Characterization and Classification

a. Inspection Scope

The inspectors reviewed the licensees radiochemical sample analysis results for each of the licensees waste streams, including dry active waste, spent primary resins, blowdown evaporator bottoms, and process stream filters. The inspectors reviewed the licensees use of scaling factors to quantify difficult-to-measure radionuclides (e.g., pure alpha or beta emitting radionuclides) to assure compliance with 10 CFR 61.55 and 10 CFR 61.56. The inspectors also reviewed the licensees waste characterization and classification program to ensure that the waste stream composition data accounted for changing operational parameters and thus remained valid between the annual sample analysis updates. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.4 Shipment Preparation

a. Inspection Scope

The inspectors reviewed packaging, surveys, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers, and licensee verification of shipment readiness for the following shipments:

• Shipment 2001-051, Resin for processing;

• Shipment 2001-070, Blowdown Evaporator Bottoms;

• Shipment 2002-027, Repair Equipment;

• Shipment 2003-017, Resin for volume reduction; and

• Shipment 2003-066, Contaminated Laundry for Processing.

The inspectors verified that the requirements of applicable transport cask Certificate of Compliance were met for each shipment and verified that the recipient was authorized to receive the packages. The inspectors verified that the licensees procedures for cask loading and closure were consistent with the vendors approved procedures. The inspectors observed radiation worker practices to verify that the workers demonstrated adequate skills to accomplish each task and to determine if the shippers were knowledgeable of the shipping regulations and whether shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport with respect to NRC Bulletin 79-19 and 49 CFR Part 172 Subpart H.

The inspectors reviewed the records of training provided to personnel responsible for the conduct of radioactive waste processing and radioactive shipment preparation activities to verify that the licensee provided training consistent with NRC and Department of Transportation requirements. The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.5 Shipping Records

a. Inspection Scope

The inspectors reviewed five non-excepted package shipment manifests/documents completed in 2001 through 2003 to verify compliance with NRC and Department of Transportation requirements (i.e., 10 CFR Parts 20 and 71, and 49 CFR Parts 172 and 173). The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

.6 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed condition reports, audits and self assessments that addressed radioactive waste and radioactive materials shipping program deficiencies since the last inspection, to verify that the licensee had effectively implemented the CAP and that problems were identified, characterized, prioritized and corrected. The inspectors also verified that the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

The inspectors reviewed corrective action reports from the radioactive material and shipping programs initiated since the previous inspection, interviewed staff and reviewed other associated documents to determine whether the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

• Evaluation of safety significance/risk and priority for resolution;

• Identification of repetitive problems;

• Identification of contributing causes;

• Identification and implementation of effective corrective actions;

• Resolution of NCVs tracked in corrective action system(s); and

• Implementation/consideration of risk significant operational experience feedback.

The inspection activity constitutes one inspection sample.

b. Findings

No findings of significance were identified.

2PS3 Radioactive Material Control Program (71122.03)

.1 Failure to Perform Adequate Surveys and Maintain Control of Licensed Radioactive

Material

a. Inspection Scope

The inspectors reviewed the circumstances associated with the unrestricted release of shipment 2CV-203 (approximately 5,000 disintegrations per minute (dpm) internal contamination on the inlet side of the valve) that occurred on October 13, 2003, upon receipt of the valve at the vendor repair facility. Specifically, the inspectors reviewed the licensees initial Action Request, investigative documents (including worker statements and a time line of the event), survey data, and discussed the incident with the radiation protection manager and several members of the Radiation protection staff.

b. Findings

Introduction:

The inspectors identified a NCV of 10 CFR 20.1501 which led to a subsequent violation of 10 CFR 20.1802. The issue had very low safety significance (Green) and was identified through a self-revealing event, when a valve was shipped from Point Beach Nuclear Plant without being identified as containing radioactive material. An inadequate survey of 2CV-203 was performed prior to the valves release, since the survey did not evaluate the concentrations or quantities of radioactive materials inside the valve. Licensed radioactive material was found inside the valve by the vendor at its repair facility prior to performing work on the valve. Despite adequate station procedures and training of Radiation protection personnel for proper determination of materials being evaluated for release or control at the RCA boundary, the valve was inadequately surveyed and released for shipment to the vendor, as unrestricted material.

Description:

On October 11, 2003, an RPT evaluated a primary relief valve (2CV-203)for release for unrestricted handling. It was a new valve that had been installed for approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> in the plants primary (contaminated) system and then had been removed. The ends of the valve were capped for Foreign Material Exclusion purposes and then the valve was moved to the RCA access point. The information relating to the specific circumstances of the history of the valve was not known to the evaluating RPT.

The RPT considered the valve to be new, with no history of exposure to contaminated fluids. The exterior surfaces of the valve (and foreign material exclusion caps) were surveyed and found to be <[MDA less than minimal detectable activity] via contamination smears, and then the valve was then released from the RCA for unrestricted handling. The valve was shipped as unrestricted material to a vendor that was out of state. Upon receipt at the vendor repair facility, the valve was surveyed by direct frisk on the inlet side and found to have around 5,000 disintegrations per minute fixed and approximately 200 counts per minute loose surface contamination. The valve was controlled as radioactive material, and the licensee was notified. The shipping container was surveyed, as well as the transporting vehicle, and both were found to have no detectable contamination in them. The licensee then initiated an action request and an apparent cause evaluation. The event was self-revealing when the vendor discovered licensed radioactive material in the valve that was released by the Point Beach Nuclear Plant for unrestricted handling.

Analysis:

The inspectors determined that the issue was associated with the Program and Process and Human Performance attributes of the Public Radiation Safety Cornerstone and affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain. Also, the issue involved an occurrence in the licensees radioactive material control program that is contrary to both NRC regulations and licensee procedures.

Therefore, the issue was considered to be more than minor.

The inspectors determined that the RPTs lack of knowledge, as to the radiological history of the valve in question, led to the unrestricted release of licensed radioactive material into the public domain outside the owner controlled area. Transportation was not a consideration in the assessment of the significance of the finding. Although the valve was transported, it was not a radioactive material shipment classified as Schedule 5-11. As such, the inspectors utilized Manual Chapter 0609, Appendix D, Public Radiation Safety SDP, to assess the significance of the finding. Since public radiation exposure was not greater than 0.005 rem (5 millirem) and the licensee did not have more than five radioactive material control occurrences in the previous 8 quarters, the inspectors concluded that the finding was of very low safety significance (Green).

Enforcement:

Title 10 CFR 20.1501 requires that the licensee perform reasonable and necessary surveys to comply with the regulations in 10 CFR Part 20, and to evaluate the concentrations or quantities of radioactive material. Title 10 CFR 20.1802 requires that licensees control and maintain constant surveillance of licensed material that is in a controlled or unrestricted area and that is not in storage. On October 11, 2003, the licensee failed to perform reasonable and necessary surveys of primary plant components that had been exposed to, and contaminated by primary reactor coolant (5,000 disintegrations per minute fixed and approximately 200 counts per minute loose surface contamination). As a result, the licensee failed to control and maintain constant surveillance of licensed material (contamination within the component internals) that was in a controlled or unrestricted area and that was not in storage. These failures constitute violations of 10 CFR 20.1501 and 10 CFR 20.1802, respectively. The licensee entered the issue into its corrective action program (CAP 051000). Because the violations were of very low safety significance and were entered into the licensees CAP, the violations are being treated as an NCV consistent with Section VI.A. of the NRC Enforcement Policy. (NCV 05000301/2003009-09).

4OA1 Performance Indicator (PI) Verification

Cornerstones: Mitigating Systems, Emergency Preparedness

a. Inspection Scope

The inspectors sampled the licensees submittal for the PIs and periods listed below.

The inspectors used PI definitions and guidance contained in Revision 2 of Nuclear Energy Institute Document 99-02, "Regulatory Assessment Performance Indicator Guideline" to verify the accuracy of the PI data. The inspectors reviewed selected applicable conditions and data from logs, licensee event reports, and CAP documents from January 2002 through September 2003 for the RHR System Unavailability PI, and July 2002 through September 2003 for the Heat Removal and Emergency AC Power Systems Unavailability PIs. The inspectors independently performed calculations where applicable. The inspectors compared that information to the information required for each PI definition in the guideline, to ensure that the licensee reported the data accurately.

For the Dual Unit PIs, the inspectors reviewed licensee records associated with PI data reported to the NRC for the period January 2002 through September 2003, with the exception of records associated with a drill conducted on August 1, 2002, which were related to Unresolved Item (URI) 50-266/02-10-04 and 50-301/02-10-04. Reviewed records included: revised procedural guidance on identifying key ERO positions; assessments of drill and exercise performance opportunities during pre-designated Control Room Simulator training sessions, the 2002 biennial exercise, and drills; and revisions of the roster of personnel assigned to key ERO positions. The inspectors also reviewed records of the results of periodic ANS operability tests.

These observations constituted nine inspection samples. The following PIs were reviewed:

Unit 1

• Heat Removal System Unavailability

• RHR System Unavailability

• Emergency Air Conditioning Power Systems Unavailability Unit 2

• Heat Removal System Unavailability

• RHR System Unavailability

• Emergency Air Conditioning Power Systems Unavailability Dual Unit

• ERO Drill Participation

• Drill/Exercise

• Alert and Notification System

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

.1 Manipulator Crane Cable Entanglement

a. Inspection Scope

During the week of October 18, 2003, the inspectors reviewed the licensees response to the Unit 2 refueling manipulator crane gripper interlock cable becoming entangled with the hoist lift cable during spent fuel movements in support of core off-loading activities. The inspectors observed and evaluated licensee actions to recover a suspended fuel assembly, untangle the gripper interlock and hoist cables, and place the system in a safe condition. During troubleshooting and recovery efforts, the inspectors reviewed the adequacy and application of configuration control and the design change processes. This observation constituted one inspection sample.

b. Findings

No findings of significance were identified.

.2 Solar Magnetic Disturbance Affects on Electrical Grid Stability

a. Inspection Scope

During the week of November 1, 2003, the inspectors reviewed the licensees response to grid instabilities caused by solar magnetic disturbances. The inspectors reviewed the impact of the disturbances on both Units and the decision to reduce Unit 1 power to 83 percent as a result of grid stability concerns. The inspectors verified that the disturbances had ended prior to returning Unit 1 to full power operations. This observation constituted one inspection sample.

b. Findings

No findings of significance were identified.

.3 (Closed) Licensee Event Report (LER) 50-266/301/2002-003-01: Possible Common

Mode Failure of AFW Due to Partial Clogging of Recirculation Orifices Licensee Event Report 50-266/301/2002-003-01 supplemented LER 50-266/301/2002-003-00, which was previously discussed in NRC Special Inspection Report 50-266/2002-15; 50-301/2002-15, Section 5.2; NRC 95003 Supplemental Inspection Report 50-266/2003-07; 50-301/2003-07; and NRC Final Significance Determination Letter, dated December 11, 2003. The supplemental LER discussed the apparent causes and human performance factors associated with the possible common mode failure of AFW due to partial clogging of recirculation orifices.

The inspectors reviewed the supplemental LER and did not identify any findings of significance. The licensee documented the failure to identify the degraded condition of the AFW recirculation orifice flow in CAP029908. This supplemental LER is closed.

4OA4 Cross-Cutting Aspects of Findings

1. A finding discussed in Section 1R05.b.1 of this report had, as its primary cause, a

problem identification and resolution deficiency, in that corrective actions for combustible loading concerns in Fire Zone 187 had initially been successful following the licensees quality assurance organization escalation of the issue in October 2002.

Despite this level of attention, the inspectors identified in November 2003 that plastic hoses, plastic sheets, paper office supplies, and plastic bottles had been reintroduced to the zone without prior evaluation.

.2 A finding discussed in Section 1R13.1 of this report had, as its primary cause, two

human performance deficiencies concerning the RA associated with removing RHR pumps from the shutdown cooling mode of operation. First, despite reviewing the activity prior to the outage, probabilistic RA and outage planning personnel did not identify entry into the yellow risk category. Second, once relaxed, operations personnel did not increase the performance frequency of shutdown safety assessment checklists during periods of changing plant conditions so as to have been able to identify the unavailability and increased risk associated with the activity.

.3 A finding discussed in Section 1R14.1 of this report had, as its primary cause, a human

performance deficiency, in that perceived time pressure, concurrent watch turnovers, lack of specific supervisory briefings, operator fatigue, and ineffective peer and self-checking resulted in a licensed senior reactor operator and reactor operator not recognizing that the suction path to the B RHR pump was isolated prior to starting the pump.

.4 A finding discussed in Section 1EP6 of this report, as its primary cause, a human

performance deficiency in two respects. First, the decision not to train on the sheltering option represented a missed opportunity to train personnel on the full range of available protective action recommendations. Second, the Assistant Operations Manager, Operations Training Shift Manager, two Shift Managers, and an Emergency Preparedness Supervisor in the classroom failed to stop the training despite having been informed at the beginning of the class that the most current revision would not be used.

.5 A finding discussed in Section 2OS1.4.b.1 of this report had, as its primary cause, a

human performance deficiency, in that despite adequate station procedures and training for radiation protection personnel concerning VHRA key control, posting, and guarding requirements, the gate to the Unit 2 under-reactor vessel area was left unguarded for several hours.

.6 A finding discussed in Section 2PS3 of this report had, as its primary cause, a human

performance deficiency, in that despite adequate station procedures and training of Radiation protection personnel for proper determination of materials being evaluated for release or control at the RCA boundary, a valve was inadequately surveyed and released for shipment to the vendor, as unrestricted material.

4OA5 Other Activities

.1 RPV Head and Vessel Head Penetration Nozzles (Temporary Instruction (TI) 2515/150,

Revision 2)

a. Inspection Scope

The inspectors reviewed the licensees activities in response to the requirements of Order EA-03-009, Issuance of Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors, (NRC ADAMS Accession Number ML030410402), issued on February 11, 2003. To support the evaluation of licensees activities implemented in accordance with Order EA-03-009, NRC staff issued TI 2515/150, Revision 2, Reactor Pressure Vessel Head and Vessel Head Penetration Nozzles (NRC Order EA-03-009), on August 4, 2003.

For Unit 2, the licensees effective degradation years calculation of 16.6 placed the Unit in the primary water stress corrosion cracking susceptibility category of High (plants with a calculated effective degradation years value greater than 12). Based on the High category the licensee performed a bare metal visual examination of 100 percent of the RPV head surface (Top of Vessel Head Visual Examinations) and UT of each RPV head penetration nozzle (Under-Head Examinations) during this refueling outage.

Summary The licensee did not identify any leaking vessel head penetration nozzles.

b. Evaluation of Inspection Requirements In accordance with requirements of TI 2515/150, Revision 2, the inspectors evaluated and answered the following questions:

For each of the examination methods used during the outage, was the examination:

Performed by qualified and knowledgeable personnel?

Top of Vessel Head Visual Examinations Yes. The inspectors verified that the visual examination of the head was performed by qualified and knowledgeable Level II and Level III VT-2 examiners. In addition to the requirements for ASME VT-2 examiners, examination personnel received instruction in the type of RPV leakage discovered in the industry prior to performing examinations.

Under-Head Examinations Yes. The ultrasonic, and head vent line dye penetrant examinations were performed by qualified and knowledgeable Level II and III personnel.

Performed in accordance with demonstrated procedures?

Top of Vessel Head Visual Examinations Yes. The bare metal remote visual examinations were conducted in accordance with Nondestructive Examination Procedure NDE-757, Visual Examination For Leakage of Reactor Pressure Vessel Penetrations, Revision 2. Lighting and resolution capabilities were demonstrated by the ability to resolve lower case character height of 0.158 inches at a maximum distance of 6 feet with a minimum illumination of 15 foot candles.

Under-Head Examinations Yes. The ultrasonic inspections were performed in accordance with Framatome ANP Nondestructive Examination Procedure 54-ISI-100-09, Remote Ultrasonic Examination of Reactor Head Penetrations, dated September 9, 2002. The equipment demonstrated the ability to detect cracking in control rod drive mechanism (CRDM)penetration tubes removed from the Oconee Nuclear Power Station and Electric Power Research Institute/Modification Rework Package Mockup G.

3. Able to identify, disposition, and resolve deficiencies?

Top of Vessel Head Visual Examinations Yes. The inspectors concluded from the review of the documentation that the licensee had sufficient access to perform a remote visual examination of 100 percent of the bare metal of the reactor head as well as 360 degree coverage of each penetration. No evidence of penetration leakage or boric acid accumulation was identified.

Under- Head Examination Yes. The UT examinations were conducted from the inside of the vessel head penetration (VHP). The procedure provided for documentation of equipment setup; calibration; detection; location; and characterization of axial, circumferential, and off-axis inside diameter and outside diameter initiated flaws in the CRDM nozzle base metal.

Complete procedural coverage was obtained on all VHPs. No flaws were identified.

4. Capable of identifying the primary water stress corrosion cracking (PWSCC)

and/or RPV head corrosion phenomena described in Order EA-03-009?

Top of Vessel Head Visual Examinations Yes. The inspectors determined through interviews with inspection personnel, and reviews of the documentation that the licensees efforts were capable of detecting and characterizing PWSCC and/or RPV head corrosion phenomena described in NRC Order EA-03-009. The inspectors determined that the inspection personnel had access for remote visual examination of the 49 head penetrations, plus the 3/4 inch head vent, with no obstructions or interferences.

Under-Head Examinations Yes. The inspectors determined through interviews with inspection personnel, reviews of the documentation that the licensees efforts were capable of detecting and characterizing PWSCC and/or RPV head corrosion phenomena described in NRC Order EA-03-009. The examinations consisted of scanning for axial and circumferential flaws within the nozzle base metal using either the rotating or blade probe. The rotating probe, consisting of a transducer head with multiple search units, was used for open bore nozzles that did not contain thermal sleeves. The blade probe was used for nozzles that contained thermal sleeves. The circumferential blade probe was designed to emit ultrasound along the long axis of the nozzle using an angle beam transducer.

The axial blade probe was designed to emit ultrasound circumferentially around the nozzle and also used an angle beam transducer.

5. What was the condition of the reactor head (debris, insulation, dirt, boron from

other sources, physical layout, viewing obstructions)?

Top of Vessel Head Visual Examinations The Unit 2 RPV head insulation consisted of mirror panels with six viewing ports cut into the insulation. This insulation replaced the 3-inch thick block contoured asbestos insulation removed in the last outage. Through discussions with inspection personnel and viewing of the videotape, the inspectors determined that the as-found pressure vessel head condition was relatively clean with no examination viewing obstructions.

A small amount of debris in the form of mastic particles from the previous asbestos insulation installation was noted; however, these did not obstruct the exam. The inspection personnel fully examined the 49 VHPs, including the 3/4 inch head vent. No boric acid deposits were observed on the reactor vessel head.

Under-Head Examinations The surface of the inner bore of the CRDM penetrations was sufficiently smooth for the UT examinations.

6. Could small boron deposits, as described in Bulletin 01-01, be identified and

characterized?

Top of Vessel Head Visual Examinations Yes. The inspectors determined through interviews with inspection personnel, reviews of procedures and inspection reports, and reviews of videotape documentation that small boron deposits, as described in the Bulletin, could be identified and characterized.

The inspectors noted that no boric acid deposits were found on the 49 VHPs, including the 3/4 inch head vent.

7. What material deficiencies (i.e., cracks, corrosion, etc.) were identified that

required repair?

None. The surface and volumetric inspections did not identify any material deficiencies that required repair associated with the 49 VHPs, including the 3/4 inch head vent.

8. What, if any, impediments to effective examinations, for each of the applied

methods, were identified (e.g., centering rings, insulation, thermal sleeves, instrumentation, nozzle distortion)?

Top of Vessel Head Visual Examinations None. The inspectors verified that there were no impediments to the remote visual examinations. The new RPV head insulation had six viewing ports to aid inspections of the head and to reduce dose associated with insulation removal.

Under-Head Examinations The inspectors verified that there were no impediments to the examinations.

What was the basis for the temperatures used in the susceptibility ranking calculation, were they plant-specific measurements, generic calculations (e.g., thermal hydraulic modeling, instrument uncertainties), etc.?

The basis for the RPV head temperature of 592 degrees F. used in the susceptibility ranking calculation is the published value in MRP-48, PWR Materials Reliability Program Response to NRC Bulletin 2001-01, dated August 2001.

10.

During non-visual examinations, was the disposition of indications consistent with the guidance provided in Appendix D of this TI? If not, was a more restrictive flaw evaluation guidance used?

No indications were identified by the non-visual (ultrasonic) examinations.

11.

Did procedures exist to identify potential boric acid leaks from pressure-retaining components above the RPV head?

Yes. The inspectors verified that visual examinations to detect potential boric acid leaks from pressure-retaining components above the RPV head were conducted in accordance with Nondestructive Examination Procedure NDE-757, Visual Examination For Leakage of Reactor Pressure Vessel Penetrations, Revision 2.

12.

Did the licensee perform appropriate follow-on examinations for indications of boric acid leaks from pressure-retaining components above the RPV head?

There was no evidence of leakage above the RPV head.

c. Findings

Partial Data Acquisition Due To Coupling Slippage.

On September 16, 2003, the licensee contractor identified (Framatome NCR 6028873-Lack of UT Coverage During U1R27 RPV Inspection) that, during the Unit 1 RPV head ultrasonic inspection in September 2002, stalling of the rotating ultrasonic probe head due to coupling slippage resulted in partial data acquisition in 10 of the 16 CRDM nozzles.

This issue was documented in the licensees corrective action system as CA053202 and CE012362. Corrective actions to prevent recurrence (redesigned coupling, backup analysts) were implemented during the current Unit 2 outage. The licensee also performed an analysis of the coverage limitations and determined that there was sufficient Unit 1 data for the testing results to remain valid. The licensee also planned to conduct an ultrasonic inspection of the CRDM nozzles during the next Unit 1 outage (U1R28). This issue will be a URI pending the inspectors review of the licensees analysis and results of the U1R28 nozzle examination (URI 05000266/2003009-01).

.2 RPV Lower Head Penetration (LHP) Nozzles (NRC Bulletin 2003-02) (TI 2515/152)

a. Inspection Scope

The inspectors reviewed the licensees activities in response to Bulletin 2003-02, which was issued on August 21, 2003. To support the evaluation of the licensees activities implemented in accordance with Bulletin 2003-02, NRC staff issued TI 2515/152, Reactor Pressure Vessel Lower Head Penetration Nozzles (NRC Bulletin 2003-02), on September 5, 2003.

Summary The licensee did not identify any signs of leakage from the RPV LHP nozzles, or degradation of the RPV lower head.

b. Evaluation of Inspection Requirements In accordance with requirements of TI 2515/152, the inspectors evaluated and answered the following questions:

For each of the examination methods used during the outage, was the examination:

Performed by qualified and knowledgeable personnel? (Briefly describe the personnel training/qualification process used by the licensee for this activity.)

Yes. The inspectors verified that the examination was performed by four qualified and certified ASME VT-2 examiners. In addition to the requirements for ASME VT-2 examiners, examination personnel received instruction in the type of RPV leakage discovered in the industry prior to performing examinations.

Performed in accordance with demonstrated procedures?

Yes. The bare metal direct visual examinations were conducted in accordance with Nondestructive Examination Procedure NDE-757, Visual Examination For Leakage of Reactor Pressure Vessel Penetrations, Revision 2. Lighting and resolution capabilities were demonstrated by the ability to resolve lower case character height of 0.158 inch at a maximum distance of 6 feet with a minimum illumination of 15 foot candles.

Able to identify, disposition, and resolve deficiencies?

Yes. The bare metal direct visual examinations were conducted in accordance with Nondestructive Examination Procedure NDE-757, Visual Examination For Leakage of Reactor Pressure Vessel Penetrations, Revision 2, which provides for indication recording, evaluation and disposition.

4. Capable of identifying pressure boundary leakage as described in the bulletin

and/or RPV lower head corrosion?

Yes. The inspectors verified that the bare metal visual examinations of the 36 bottom mounted instrumentation nozzles were conducted in accordance with Nondestructive Examination Procedure NDE-757, Visual Examination For Leakage of Reactor Pressure Vessel Penetrations, Revision 2. The examinations were performed directly, with lighting provided by flood lights, fluorescent drop lights and hand held flashlights.

5. What was the physical condition of the RPV lower head (e.g., debris, insulation,

dirt, boric acid deposits from other sources, physical layout, viewing obstructions)?

The inspectors verified through direct inspection that the bottom head insulation had been completely removed, thereby exposing the 36 LHP nozzles with no viewing obstructions. Surrounding each LHP nozzle was an inconel weld pad. The reactor vessel bottom coating (silver paint) was in good condition with areas of red/brown staining attributed to reactor cavity seal leakage. The silver coating was not applied to the weld pad or nozzles.

6. Could small boric acid deposits, as described in the Bulletin 2003-02, be

identified and characterized?

Yes. The inspectors verified that each of the 36 LHP nozzles were examined 360 degrees around their circumference, as well as bare metal for at least 6-12 inches above the highest LHP. All nozzles were examined with no evidence of leakage, (i.e., small boric acid deposits), from the LHP nozzle interface region.

7. What material deficiencies (i.e., cracks, corrosion, etc.) were identified that

required repair?

None. The visual inspections did not identify any material deficiencies that required repair associated with the 36 LHP nozzles.

8. What, if any, impediments to effective examinations, for each of the applied

nondestructive examination methods, were identified (e.g., insulation, instrumentation, nozzle distortion)?

The inspectors verified through direct observation of the lower head that there were no impediments to the direct visual examinations. The RPV bottom head insulation was completely removed to provide access to the LHP nozzle interface.

9. Did the licensee perform appropriate follow-on examinations for indications of

boric acid leaks from pressure-retaining components above the RPV lower head?

Yes. As noted above, there were no boric acid deposits on the RPV bottom head. The inspectors verified that the red/brown staining was appropriately attributed to reactor cavity seal leakage. The leakage appeared to have run down the side of the reactor from the cavity seal area picking up trace amounts of iron oxide and depositing it on the coated bottom head area in the form of red/brown stains.

c. Findings

No findings of significance were identified.

.3 (Closed) URI 50-266/03-02-02; 50-301/03-02-02: This URI encompassed the following:

the licensees 50.59 process did not refer emergency planning issues to its 50.54(q)process for further screening; there was a lack of instructions, procedures, or drawings to help communications technicians assess problems in the Emergency Operations Facility (EOF); equipment in the EOF or Joint Public Information Center (JPIC) could be placed out of service or replaced by non-licensee personnel without licensee knowledge; and the capability to remotely monitor Emergency Notification System (ENS) operability was degraded since January 17, 2003.

The inspectors completed a walkdown of the EOF, which was located in the Site Boundary Control Center building, and discussed associated emergency preparedness-related equipment maintenance and configuration control matters with emergency preparedness staff. The inspectors also reviewed and discussed a white paper on EOF equipment configuration control, the minutes of an early August Plant Health Committee meeting, and records of external and internal correspondence addressing EOF equipment configuration control matters. The inspectors reviewed the October 2003 draft revision of the licensees emergency planning excellence plan regarding equipment configuration control issues. The inspectors concluded that adequate actions were either completed or were underway and being adequately tracked to ensure that emergency planning-related equipment in the Site Boundary Control Center would not undergo preventive or non-scheduled maintenance without the prior approval of the Emergency Preparedness Manager or the work control centers management. The inspectors also concluded that adequate measures were in place to alert telecommunications specialists of a degrade to ENS telephone equipment and to help technicians diagnose ENS equipment problems.

The inspectors also reviewed and discussed the current letter of agreement between the licensee and Wisconsin Public Service Corporation regarding the use of the latters facilities in Green Bay, Wisconsin, as an alternate EOF and a JPIC. The inspectors concluded that the current agreement included adequate provisions for notifying relevant Point Beach personnel of planned emergency equipment-related changes prior to implementation of such changes. No violations of NRC requirements were identified.

This URI is considered closed.

4OA6 Meetings

.1 Exit Meeting

On January 6, 2003, the resident inspectors presented the inspection results to Mr. A. Cayia and other members of his staff, who acknowledged the findings. The licensee did not identify any information, provided to or reviewed by the inspectors, as proprietary in nature.

.2 Interim Exit Meetings

Interim exits were conducted for:

• Inservice Inspection (IP 71111.08), Temporary Instruction TI 2515/150, Revision 2, and Temporary Instruction TI 2515/152, with Mr. A. Cayia on October 17, 2003.

• Radiation Protection Inspection with Mr. A. Cayia, on November 7, 2003.

• Radiation Protection Inspection with Ms. R. Milner, on October 24, 2003.

• Emergency Preparedness program and performance indicators inspection meeting with Mr. A. Cayia on October 31, 2003.

• Fire Protection with Mr. D. Schoon and Mr. D. Fadel on November 14, 2003.

4OA7 Licensee-Identified Violations

The following violation of very low significance was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Manual, NUREG-1600, for being dispositioned as a NCV.

Cornerstone: Mitigating Systems

• Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures be established to assure that applicable regulatory requirements and design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, prior to November 2003, the licensee had not recognized that the 30-day primary containment integrity function of the Unit 1 and 2 purge supply and exhaust system penetration isolation valves was dependent on instrument air, a non-safety system that could not be relied upon to mitigate the consequences of a design basis accident.

Specifically, the licensee had not verified that adequate emergency and abnormal operating procedures were in place such that IA system restoration and maintenance of the purge supply and exhaust valve boot seals was assured prior to the loss of containment integrity function. The licensee entered the condition into its corrective action program as CAP051581, VNPSE [Ventilation Purge Supply and Exhaust] Valves IST [Inservice Inspection Test] Acceptance Criteria Incorrect Not Conservative.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

A. Cayia, Site Vice-President

J. McCarthy, Director of Site Operations

J. Jensen, Plant Manager

T. Breene, Site Assessment Manager

J. Boesch, Maintenance Manager

J. Connolly, Regulatory Affairs Manager

G. Casadonte, Fire Protection Coordinator

D. Fadel, Site Engineering Director

F. Flentje, Senior Regulatory Compliance Specialist

M. Holzmann, Nuclear Oversight Supervisor

N. Hoefert, Engineering Programs Manager

R. Hopkins, Internal Assessment Supervisor

B. Jensen, Level III

C. Jilek, Maintenance Rule Coordinator

T. Kendall, Program Engineering

B. Kopetsky, Security Coordinator, Point Beach

C. Krause, Senior Regulatory Compliance Engineer

R. Ladd, Fire Protection Engineer

K. Locke, Regulatory Compliance

R. Milner, Emergency Planning Manager

T. Petrowsky, Design Engineer Manager

D. Schoon, Plant Manager (Acting) and Operations Manager

M. Schug, Assistant Operations Manager

R. Scott, Regulatory Affairs Manager (Acting)

P. Schwartz, Emergency Preparedness Supervisor

J. Schweitzer, Site Engineering Director and Production Planning Manager

D. Shannon, Radiation Protection Manager (Acting)

C. Sizemore, Training Manager

P. Smith, Operations Training Supervisor

A. Spaulding, Emergency Planning Specialist

J. Strharsky, Planning and Scheduling Manager

R. Turner, Inservice Inspection Coordinator

S. Thomas, Radiation Protection Manager

Nuclear Regulatory Commission

P. Louden, Chief, Reactor Projects Branch 5

A. Vegel, Chief, Reactor Projects Branch 7

D. Spaulding, Point Beach Project Manager, NRR

Attachment

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000266/2003009-01 URI Partial Data Acquisition Due To Coupling Slippage

05000266/2003009-02 NCV Inadequate Corrective Actions for Control of Transient

05000301/2003009-02 Combustibles

05000266/2003009-03 URI Sprinkler Head Locations Not In Accordance With Fire

05000301/2003009-03 Code

05000301/2003009-04 FIN Inadequate Risk Assessment Associated With Removing RHR Pumps From The Shutdown Cooling Mode Of Operation

05000301/2003009-05 NCV Operator Error Results In Starting a Residual Heat Removal Pump With the Suction Valve Shut

05000266/2003009-06 URI Non-Safety Related Worm and Worm Gears Used in Safety-Related Motor Operated Valve Actuators

05000266/2003009-07 FIN Protective Action Recommendation Training for

05000301/2003009-07 Licensed Reactor Operators Using an Outdated Procedure

05000301/2003009-08 NCV Failure to Control Access to a Very High Radiation Area

05000301/2003009-09 NCV Failure to Perform Adequate Surveys and Maintain Control of Licensed Radioactive Material.

Closed

05000266/2003009-02 NCV Inadequate Corrective Actions for Control of Transient

05000301/2003009-02 Combustibles

05000301/2003009-04 FIN Inadequate Risk Assessment Associated With Removing RHR Pumps From The Shutdown Cooling Mode Of Operation

05000301/2003009-05 NCV Operator Error Results In Starting a Residual Heat Removal Pump With the Suction Valve Shut

05000266/2003009-07 FIN Protective Action Recommendation Training for

05000301/2003009-07 Licensed Reactor Operators Using an Outdated Procedure

05000301/2003009-08 NCV Failure to Control Access to a Very High Radiation Area Attachment

05000301/2003009-09 NCV Failure to Perform Adequate Surveys and Maintain Control of Licensed Radioactive Material.

50-266/03-02-02 URI Licensees 50.59 Process Did Not Refer Emergency 50-301/03-02-02 Planning Issues to Its 50.54(q) Process for Screening 50-266/301/2002-003-01 LER Possible Common Mode Failure of AFW Due to Partial Clogging of Recirculation Orifices

Discussed

None.

Attachment