IR 05000266/1999002

Insp Repts 50-266/99-02 & 50-301/99-02 on 990105-0222. Violations Noted.Major Areas Inspected:Licensee Operations, Maint,Engineering & Plant Support

ML20207L205
Person / Time
Site:	Point Beach
Issue date:	03/10/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20207L119	List: IR 05000266/1999002 ML20207L116 ML20207L121
References
50-266-99-02, 50-266-99-2, 50-301-99-02, 50-301-99-2, NUDOCS 9903180032
Download: ML20207L205 (27)

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U.S. NUCLEAR REGULATORY COMMISSION REGION ll1 Docket Nos: 50-266;50-301 License Nos: DPR-24; DPR-27 Report No: 50-266/99002(DRP); 50-301/99002(DRP)

Licensee: Wisconsin Electric Power Company '

l Facility: Point Beach Nuclear Plant, Units 1 & 2 !

Location: 6610 Nuclear Road Two Rivers, WI 54241 Dates: January 5 through February 22,1999 l

i inspectors: F. Brown, Senior Resident inspector P. Louden, Resident inspector P. Simpson, Resident inspector J. Lara, Senior Resident inspector, Kewaunee M. Kunowski, Project Engineer Approved by: Roger D. Lanksbury, Chief Reactor Projects Branch 5

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I EXECUTIVE SUMMARY Point Beach Nuclear Plant, Units 1 & 2 I NRC Inspection Report 50-266/99002(DRP); 50-301/99002(DRP)

This inspection included aspects of licensee operations, maintenance, engineering, and plant support. The report covers a 7-week inspection period by the resident inspector Operations

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The licensee promptly and thoroughly evaluated an industry operating experience bulletin on a certain type of electrical circuit breaker. The licensee demonstrated an appropriately conservative operating philosophy in declaring inoperable several of these breakers and shutting down the operating unit after a similar breaker in a nonsafety-related application was found to be physically degraded. While the licensee's initial i operability determination for this issue failed to identify all the potential system impacts, l the questioning attitude of an on-shift operating crew led to the conservative decision to '

shut down the Unit until the problem was resolved. (Section 01.1)

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Better maintenance prac* ices and more timely completion of a breaker replacement project could have eliminated the need to shut down the operating unit. (Section 01.1) i a'

During the Unit 1 startup, the duty shift superintendent (the lead senior reactor operator) l performed a thorough pre-job brief and provided effective overview of control room activities. Reactor engineering personnel provided an acceptable estimated critical rod position calculation for the Unit 1 startup. (Section 01.2)  ;

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The inspectors identified that the licensee lacked alarm response instructions for operationally significant alarms generated by the plant process computer system and i did not have procedural controls for disabling control room alarms. (Section 01.2)

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The inspectors performed an inspection of the Unit 2 containment to assess cleanliness 1 and safety-related system and component readiness for unit restart. Other than minor iterns which the licensee addressed, systems, components, and general housekeeping '

were appropriate for unit startup. (Section O2.1)

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The inspectors identified four areas of concern with the licensee's use and implementation of abnormal operating procedures and emergency operating procedures: the procedure deviation process, immediate operator actions, reference procedure use, and AOP exit requirements. Two examples of a violation of 10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings,"

were identified. (Section O3.1)

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The licensee did not routinely evaluate the impact of inoperable, degraded, or nonconforming equipment unless the equipment was required by Technical Specifications. While acceptable within the regulations, this practice made the licensee vulnerable when the failure of non-Technical Specification-required equipment had an

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impact on the operability of equipment with more safety significance, as in the facade i freeze protection case described in inspection Report 50-266/99004(DRP).

(Section 03.2) i Maintenance

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Two major refueling outage surveillance tests were conducted well. All safety-related i equipment functional requirements were satisfied. Operators displayed good questioning attitude in response to the questionable performance of several valves ,

during a third surveillance test, and the operations test director suspended the testing )

activity. (Section M1.1)

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Operators failed to promptly enter applicable abnormal operating procedures following i an unanticipated log of power to safety-related buses. Restoration of power to the l buses took considerabiy L,ger than during a similar event in 1997 because of a less l focused operator response (Section M1.1) '

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TN licensee completed ma ny important to safety modifications during the Unit 2 refueling outage. Examples included reactor vessel baffle bolt replacement, main control board wire separation, and over-pressure protection for containment penetrations and motor operated valves. (Section M2.1)

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There were several examples of safety-related equipment that failed post-maintenance testing and periodic surveillance tests and an instance where foreign material (pieces of a cloth rag) was left in the reactor coolant system after maintenance activities and caused a minor water hammer in the chemical and volume control system. The maintenance-related problems were more significant than those otaerved during previous outages. (Section M2.2)

Enaineerina

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The licensee was slow to recognize generic weaknesses in the programs for controlling i the use of lubricants in safety-related applications. Examples of the problems included inconsistencies among various licensee documents, and poor follow-through by j engineerir.g staff or poor communications between engineering groups when addressing lubrication issues. (Section E1.1)  ;

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The inspectors determined that t5e licensee's evaluation of cross-tying safety-related l 480 volt buses was thorough and well documented. Equipment configuration restrictions specified in the evaluation were verified by the inspectors to have been properly implemented. (Section E2.1)

i Plant Suopolt l I

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Throughout the inspection period. the inspectors observed radiological control postings j and radiation protection technician performance during tours of the radiologically )

controlled area, including Unit 2 containment. Postings and surveys for radiological j areas were appropriate and current. Technicians provided appropriate radiological I oversight of work activities. (Section R1)

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Report Detgils Summary of Plant Status The inspection period started with Unit 1 at full power. On January 5,1999, Unit 1 power was reduced to approximately 23 per cent as part of a Technical Specification (T/S)-required shutdown associated with the apparent inoperability of both safety injection pumps, as described in Inspection Report (IR) 50-266/99004(DRP). The power reduction was terminated when the NRC issued a notice of enforcement discretion. Full power operations were resumed a day later. Unit 1 was shut down on January 22, when,the licensee identified a potential problem with 4160-volt electrical circuit breakers. The unit was restarted on January 24 and remained at full power through the end of the period. Unit 2 remained in a refueling outage throughout the perio . Operations 01 Conduct of Operations 1 I

O1.1 Identification of Pott 1tial Problems with Safety-Related Electrical Breakers

' Inspectinn Scope (Inspection Procedure (IP) 71707)

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The inspectors reviewed the licensee's actions taken in response to an industry operating experience bulletin describing problems with Westinghouse type "DH" electrical breaker Observations and Findinas Another nuclear utility experienced a problem with a nonsafety-related Westinghouse type "DH" electrical breaker on January 13,1999. The problem involved a block of non-conductive shielding on the breaker arc chute which had come loose and jammed the breaker operating mechanism. An operational experiel . . report was distributed on '

January 19, and on January 21, the Point Beach operati..g experience staff identified that this style breaker was used in safety-related applications at Point Beach. This fact was entered into the licensee's corrective action program to ensure that it was promptly evaluate In respor.se to the identified concern, the licensee established an inspection plan to determine whether the shielding blocks in Point Beach's DH-style breakus were adequately restrained. The breaker inspections identified that shielding blochs in several safety-related breakers were loose, and a shielding block in a nonsafety-related l breakerwas found to have fallen onto the operating mechanism. An operability determination (OD) completed on January 22 appropriately concluded that the bloc'k in the safety-related breakers might eventually fall onto or into the operating mechanis While the initial OD failed to identify all the potential system impacts, the questioning attitude of an on-shift operations crew led to the determination that a reactor protection l system function should be declared inoperable because of the potential for a l

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l malfunction of a safety-related breaker. This resulted in the operating unit (Unit 1) being 1 shut down on January 22.

! The licensee modified all the safety-related DH-style breakers, and Unit 1 was restarted l on January 24. The modification provided reasonable assurance that the shielding block would not fallinto the operating mechanis While the licensee response to the industry operating experience bulletin was prompt, thorough, and appropriate, better maintenance practices could have resulted in earlier identification and correction of the degraded (loose) shield blocks. The licensee was in the process of performing a long-term replacement of the DH-style breakers with newer vacuum breakers; however, the replacement initiative had not been completed prior to the identification of this proble Conclusions The licensee promptly and thoroughly evaluated an industry operating experience bulletin on a certain type of electrical circuit breaker. The licensee demonstrated an appropriately conservative operating philosophy in declaring inoperable several of these breakers and shutting down the operating unit after a similar breaker in a nonsafety-related application was found to be physically degraded. While the licensee's initial operability determination for this issue failed to identify all the potential system impacts, the questioning attitude of an on-shift operating crew led to the conservative decision to shut down the Unit until the problem was resolve l l

01.2 Unit 1 Startuo i Inspection Scope (IP 71707)

The inspectors observed portions of the Unit 1 startup on January 24,1999. In addition l the inspectors reviewed the following documents: j

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Operating Procedure (OP) 18, " Reactor Startup," Revision 33

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OP 18, Appendix A, " Estimated Critical Position Calculation," Revision 7

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Abnormal Operating Procedure (AOP) 68, " Stuck Rod or Malfunctioning Position Indication Unit 1," Revision 10

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Reactor Engineering Instruction 44.0, " Shutdown Margin for an Operating Reactor." Observations and Findinas

. The inspectors observed the duty shift superintendent (DSS) perform a pre-job briefing with the operators and reactor engineers prior to reactor startup. The briefing thoroughly covered command and control, roles, responsibilities, recent equipment i

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l issues, and reactivity management. During the Unit 1 startup, the DSS effectively maintained oversight of the control room. The DSS appropriately did not become intimately involved in the evolution and provided direction and guidance as neede The inspectors verified the reactor engineers properly calculated an estimated critical rod position. The reactor achieved criticality within 25 steps of the estimated rod position. This was within the calculated acceptarice ban During the Unit 1 startup, control rod misalignment alarms from the plant process computer system (PPCS) were frequently received. Response to these alarms resulted in multiple entries into T/S action statements, and in one instance also required entry into AOP 68. The inspectors verified that operators complied with the T/S action <

requirements and correctly implemented the applicable mrtions of AOP 68. The !

inspectors identified a general concern regarding AOP usage which is discussed in detailin Section O3.1 of this repor The inspectors determined that the licensee did not have any alarm response instructions for PPCS-generated, operationally significant alarms, such as * Rod Misalignment." The inspectors identified that while many PPCS generated alarms also had corresponding control board annunciators, some did not. The inspectors were concerned that operators did not have sufficient guidance to respond to operationally significant PPCS alarms that did not have a corresponding control room alarm. The inspectors discussed the t.oncern with plant management, who indicated that alarm response instructions for operationally significant PPCS alarms would be included as part of the PPCS upgrade projec Also during the startup, the inspectors observed the DSS instruct the operators to disable the " Rod Bottom Rod Drop" control board alarm. The DSS stated that the alarm had not been working properly, and that repairs had been requested. In response to inspector questions. the DSS stated that the alarm had been disabled in accordance Cth Operations Manual (OM) Procedure 3.12," Control of Equipment and Equipment Qatus," Revision 4. The inspectors found that OM 3.12 did not specifically address i r!isabling control bocrd alarms. The issue that no documented controls existed for j

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Hisabling control room alarms had been discussed in prior irs (see R 50-266/98003(DRP); 50-301/98003(DRP), Section E2.1). At that time, the licensee jissued informal guidance, until a procedure could be developed, regarding hoiv to j A disable control board alarms until a procedure could be developed. The inspectors

identified that the formal procedure had not yet been finalized, and discussed with j ( station management the concern that operators had not consistently implemented the j j informal guidance. Station management agreed that the formal procedure was neede Conclusion _s j t -

4 During the Unit 1 startup, the DSS performed r. :norough pre-job brief and provided

.j effective overview of control room activities. Reactor engineering personnel provided an I

,. acceptable estimated critical rod position calculation for the Unit 1 startup. The j inspectors identified the licensee lacked alarm response instructions for operationally f significant PPCS-generated alarms and did not have procedural controls for disabling S control room alarm (

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i l 01.3 Observation of Loadino of the Fifth Dry Storaae Soent Fuel Cask Inspection Scoon (IP 60855)

From November 9 through November 13,1998, the inspectors observed various portions of the loading of the fifth dry storage spent fuel cask to verify compliance with the applicable sections of the dry cask loading procedure Observations and Findinos

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The inspectors observed that the licensee effectively implemented lessons leamed from

. previous dry cask loadings. The inspectors did not observe any of the same problems seen during previous loads. Engineering, operations, and radiation protection personnel provided very good control of the evolutio Conclusions The loading of the fifth dry storage spent fuel cask was performed wel O2 Operational h'.tatus of Facilities and Equipment I 02.1 Unit 2 Containment Closecut Insoection Insoection Scope (IP 71707)

The inspectors performed an inspection of the Unit 2 containment to assess cleanliness and overall safety-related system readiness for unit restar l 1 Observations and Findinas The inspectors, with assistance from the Kewaunee Plant resident inspectors, verified that equipment stored in the Unit 2 containment was appropriately secured. The -

general cleanliness of the containment was found to be acceptable. No equipment or debris were identified that presented or could present a challenge to the safety-related systems or components within the containment. The inspectors noted minor items involving inadequate securing of small sample piping and miscellaneous trash. The ,

inspectors' findings were provided to outage management for resolution. The total j volume of the materialidentified would not have affected the ability of the emergency core cooling system containment sump recirculation strainer to perform its intended safety functions, c Conclusions The inspectors performed an inspection of the Unit 2 containment to assess cleanliness j

' and safety-related system and componere raadiness for unit restart. Other than minor i items which the licensee addressed the sptems, components, and general  ;

housekeeping were aporopriate for unit startu i 7 ,

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O3 Operations Procedures and Documentation 03.1 AOP and Emeroency Operatina Procedure (EOP) Use and Implementation Inspection Scope (IP 71707)

The inspectors documented in IR 50-266/98021(DRP); 50-301/98021(DRP),

Section O4.1, that the potential existed for inconsistent operator transient response because of unclear AOP use and implementation guidelines. The inspectors initiated Unresolved item (URI) 50-266/98021-02(DRP); 50-301/98021-02(DRP) to further evaluate this concer Observations and Fir dinas The inspectors reviewed OM Procedure 3.7, "AOP and EOP Procedure Sets Use and Adherence," Revision 5, and identified four areas of concern: the procedure deviation process, immediate operator actions, reference procedure use, and AOP exit requirements. Details of these four concerns are discussed belo Procedure Deviation Process Procedure OM 3.7, Sections 2.6,4.4.3, and 4.5 provided provisions for operators to

" deviate" from an AOP or EOP whenever ' .'as necessary to ensure prompt stabilization of the plant and when use of the procedae temporary change process was not practical. The procedure identified circumstances requiring procedural deviations such as when a procedure step needed to be performed in a different manner than presented, or actions were directed that were not contained within the controlling procedure and that were not parallel actions of another procedure. The procedure specified that deviations must have DSS approval, the deviation and reason for it must be logged into the station logbook, and the Duty and Call Superintendent must be notified. In addition, the NRC was to be notified within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> if required by 10 CFR 50.54(x).

The regulations contained in 10 CFR 50.54(x) authorize licensed operators to take action, including the violation of authorized procedures, if such action was deemed necessary to protect the public health and safety. The applicability of 10 CFR 50.54(x) '

was thus much more narrow than the applicability for procedure deviations specified in OM 3.7. The performance of activities affecting quakty in a manner other than as prescribed by written procedure, with the exception of the limited cases covered by 10 CFR 50.54(x), required performance of a procedure change. The requirements for procedure changes were specified in 10 CFR 50.59, and T/S 15.6.8. The licensee's '

Final Safety Analysis Report (FSAR), Chapter 12.4, " Written Procedures," described 1 AOPs and EOPs. Changes to procedures specified in the FSAR were to be screened or l evaluated to ensure that an unreviewed safety question was not created. The licensee classified AOPs and EOPs as " major" procedures. A manager's supervisory staff (the onsite review committee) had to review and approve " intent" changes to major procedures in accordance with T/S 15.6.8.2.A. In addition, "non-intent" changes to major procedures had to receive Duty and Call Superintendent approval in accordance ;

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f I with T/S 15.6.8.3.A. The OM 3.7 procedure deviation process did not address these requirements for procedure changes. Based el the failure of the deviation process to satisfy change requirements for procedures prescribing activities affecting quality, OM 3.7 was considered to be inappropriate to the urcumstances, and, as such, an example of a violation (VIO 50-266/99002-01a(DRP); 50-301/99002-01a(DRP)) of 10 CFR 50, Appendix B, Criterion The inspectors also reviewed a licensee document entitled " Guidelines for Consistent Operations." This document was a supplement to OM 3.7 in that it provided addition I !

direction on procedure use and adherence for AOPs and EOPs. Included in this l guidance were specific management expectations that operators perform certain EOP steps in a sequence other than as described in the approved EOPs. The inspectors determined that this guidance was not merely a temporary method of implementing previously reviewed and approved changes to the EOPs while the formal char.ges were being made, rather it was intended to be a permanent change to the EOP. This informal supplement to OM 3.7 was considered to be an additional example of a violation (VIO 50-266/99002-01b(DRP); 50-301/99002-01b(DRP)) of 10 CFR Part 50, Appendix B, Criterion V, in that it represented another procedure change that was not consistent with the regulatory requirement Immediate Operator Actions Plant management expected reactor operators to take certain "immediate" actions specified in the AOPs from memory. The expectation was promulgated through an informal guidance memorandum from the operations manager to operations department personnel. This guidance was deemed necessary to ensure operators took certain actions prior to referencing procedures to avoid a reactor trip. The extent and type of ,

"immediate" actions were not clearly defined or identified for each respective AOP. In )

addition, the inspectors determined that operations crews inconsistently interpreted the extent of "immediate" operator actions. Also, operations crews were not thoroughly I familiar with the expectations from operations department management regarding l Smmediate" action ,

Reference Procedure Usaae Procedure OM 3.7, Sections 4.9.1,4.9.4, and Attachment 2 defined and described how operators were to implement procedures referenced in AOP/EOP action steps. The procedures referenced provided the details of how to perform an action or activit Procedure OM 3.7 stated that the performance of the referenced activity was to be done in accordance with the requirements of the referenced procedure; however, the inspectors noted that the referenced procedure was not required to be obtained or completed. The inspectors determined that this was a deficiency with the OM guidance. Specifically, the inspectors were concerned that given the complex nature of some of the AOP and EOP referenced procedural activities, that without the "in-hand" guidance of some of the referenced activities, the operators may not be able to

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adequately accomplish the required task.

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! AOP Exit Reauirements The inspectors observed a control room crew implement AOP 68, " Stuck Rod or Malfunctioning Position Indication Unit 1 " Revision 10, on January 24,1999, in response to an indicated control rod misalignment. When the condition which required AOP entry no longer existed, the crew experienced difficulty in deciding how to exit AOP 6B. The DSS ultimately decided that the entry conditions for AOP 6B no longer existed and; therefore, the AOP no longer applied and would be exite The inspectors reviewed OM 3.7, Section 4.2, "AOP and EOP Procedure Set Entry and Exit Requirements," and could not locate any AOP exit requirements or a discussion of under what conditions or how an AOP should be exited. The inspectors discussed the issue with the operations manager, who agreed that OM 3.7 needed clarificatio Licensee's Planned Corrective Actions The inspectors discussed the above concerns with the licensee. Appropriate conective actions were planned by the licensee to address each item. Specifically, the licensee planned to remove the procedure deviation provision from OM 3.7, to incorporate all desired actions into the EOPs following completion of formal evaluations and operator training, to provide appropriate procedures to direct any immediate action steps ;

expected of operators, and to review the appropriate method for exiting AOPs and for '

using referenced procedures. These actions were entered into the plant's corrective action program, and the inspectors considered the specified completion dates to be reasonabl Conclusions The inspectors identified four areas of concern with the use and implementation of AOPs and EOPs: the procedure deviation process, immediate operator actions, reference procedure use, and AOP exit requirements. Two examples of a violation were

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identifie .2 Evaluatina the Imoact of Deoraded and Nonconformina Conditions (IPs 37551 & 71707)

During the review of licensee ODs and condition reports (CRs), the inspectors noted that ODs were routinely not performed for nonsafety-related systems, structures, and components. While such reviews are only a regulatory requirement for safety-related equipment or equipment required by T/Ss, occasions exist when performing such a review for other equipment can be beneficial. Generic Letter 91-18, "Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability," guidance stated that licensee should assess the impact of inoperability, degradation, or nonconformance associated with any system, structure, or component described in the FSA The inspectors discussed this issue with the licensee's corrective action organization and with senior plant management. The inspectors referenced the effect of plant staff's failure to assess the impact of inoperable nonsafety-related heat traces in the facade freeze protection system (see IR 50-266/99004(DRP)) as an example of why such

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l assessments could be beneficial. The licensee acknowledged the inspectors observations and were reviewing the issue at the end of the inspection period.

l 08 Miscellaneous Operations issues 08.1 LQiosed) Licensee Event Reoort (LER) 50-266/97039-00: Residual Heat Removal Loop inoperable Due to an Inoperable Component Cooling Water Pump. This event was

discussed and dispositioned in IR 50-266/07013(DRP); 50-301/97013(DRP),

l Section O2.2. The LER revealed no new issues.

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08.2 (Closed) LER 50-301/98004: Plant Operation With Reactor Core Power Levelin Excess of 1518.5 MWT [ megawatts thermal). On April 24,1998, the licensee identified that l Unit 2 operated with an actual average reactor power of 1519.1 MWT for an 8-hour shift.

l The condition resulted from the inadvertent return to service of a faulty input into one of l the plant computers used to calculate reactor thermal output. The operation of the Unit 2 reactor core at an actual average reactor power of 1519.1 MWT for an 8-hour

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i shift, constituted a violation of Facility Operating License No. DPR-27, Section 3.A,

! " Maximum Power Levels," which authorized the licensee to operate the facility at reactor core power levels not in excess of 1518.5 MWT. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation (NCV) in accordance with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-301/99002-02(DRP)). The inspectors reviewed Root Cause Evaluation 98-100, committed to be performed in the

LER, and found it to be acceptable, with recommended corrective actions being entered l into the licensee's corrective action program.

l 08.3 (Closed) URI 50-266/98021-02(DRP): 50-301/98021-02(DRP): Immediate operator actions. The issue was discussed and dispositioned in Section O3.1 of this report.

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08.4 (Closed) VIO 50-266/99002-01a and b(DRP): 50-301/99002-01a and b(DRP): AOP and EOP use and implementaticn. The issue was discussed in Section 03.1 of this report.

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l 0 [ Closed) Escalated Enforcement item (EEli 50-266/96018-07a: 50-301/96018-07a: An

! example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI,

" Corrective Action," for the failure to remove from the station T/S interpretation manual i

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(Duty & Oall Superintendent Handbook) a document that conflicted with T/S 15. l

! regarding reactor operation with only one 345-l'ilovolt transmission line in service. The

! inspectors verified that the corrective actions for this violation were taken, as discussed l

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l in the licensee's letter dated October 10,1997. For this violation, the action was to l revise the interpretation manual to remove the conflict with the T/S. In addition, the licensee revised Nuclear Power Business Unit procedure (NP) 5.1.4, " Duty and Call i Superintendent Har.dbook," the governing procedure for T/S interpretations, to explicitly ;

prohibit any interpretations that contradicted or would change the wording, meaning, or intent of any T/S requirement 0 (Closed) eel 50-266/96018-07b: 50-301/96018-07b: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure to remove from the T/S interpretation manual a document that conflicted with T/S 15.3.1.A regarding the declaration of the pressurizer power-operated relief valve as

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inoperable upon placing the control switch to the close position. The aspectors verified that the corrective action for this violation was taken, as discussed in the licensee's ;

letter dated October 10,1997. For this violation, the action was to revise the interpretation manual to remove the conflict with the T/S.

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! 0 (Closed) eel 50-266/96018-07c: 50-301/96018-07c: An example of an apparent

! violation of 10 CFR Part 50, Appendix B, Critelion XVI, " Corrective Action," for the j l failure to revise T/S 15.3A.E regarding the turbine crossover dump system, when the I

licensee determined that the T/S did not accurately specify the lowest function capability or performance level of the system. As discussed in the licensee's letter dated October 10,1997, this issue was resolved on August 6,1997, when the NRC approved

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the removal of the crossover dump system operability requirement from the T/Ss. The l licensee subsequently relocated to the FSAR a revised operability requirement for the

! system that specified the lowest function capabilit .8 (Clos _ed) eel 50-266/96018-07f: 50-301/96018-07f: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure until i

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December 16,1996, to perform an assessment of the condition identified on December 16,1994, where there was potentially inadequate protection to prevent the propagation of a single fault in a nonsafety-related backup reactor trip circuit to the reactor protection system circuits. As discussed in the letter dated October 10,1997, i the licensee determined in its evaluation of this issue on December 16,1996, that no l fault in the backup reactor trip circuit could disab'e both trains of the reactor protection )

syste .9 (Closed) eel 50-266/96018-070: 50-301/96018-070: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure to promptly correct a condition adverse to quality identified in 1994 regarding nonsafety-related cable separation and breaker thermal overload capability for circuits connected with the control of main steam isolation valve closure and engineered safety feature signal generation. The licensee replaced the suspect breakers with a model th:;t had a more reliable magnetic trip elemen .10 (Closed)IFl 50-301/97016-03: Water hammer in the Unit 2 auxiliary feedwater syste The licensee installed new "first off" check valves (AF-100 and AF-101) during the Unit 2 refueling outage. The new valves are corrective action for pressure pulsations in the auxiliary feedwater system. The previously installed swing check valves were believed to be the source of these pressure pulsations.

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11. Maintenance M1- Conduct of Maintenance l

M1.1 Refuelino Outaae Freauency Surveillance Tests

{ Inspection Scope (IP 61726)

The inspectors observed major portions of several refueling outage surveillance test Observations and Findinas Operations Refuelina Test (ORT) 3A The inspectors observed the licensee staff implement ORT 3A, " Safety injection Actuation with Loss of Engineered Safeguards AC (alternating current) (Train "A")," on February 11,1999. The inspectors also attended the pre-job briefing held on February 9,1999. The pre-job briefing was thorough and effective. During the briefing, i the test director stated that if an "off-normal" event occurred during the surveillance test, )

the on-shift operatir.g crew would resume control of the plant equipment and the test crew would provide assistance as requeste With one exception, which is described below, the surveillance test was performed wel An adequate number of personrel were assigned (16 test stations were manned). All involved personnel Used three-way communications. The test coordinator provided clear and unambiguous instructions to all involved personnel. All equipment performed its design safety function within the test acceptance criteri !

At one point during the performance of ORT 3A, the Unit 2 "A" train emergency diesel generator output breaker was briefly opened and then re-closed. During this portion of the test, the Unit 1 "A" train emergency diesel generator (G-01) was carrying the load on the Unit 2 "A" train 4160-volt (2A-05) and 480-volt (2B-03) safety-related buses. When !

the operator attempted to re-close the output breaker it did not shut resulting in a cc3plete loss of power to buses 2A-05 and 28-03. The ORT 3A procedure provided no !

contingency to address this conditio l i'

Following recognition that all power had been lost to the safety-related buses, a discussion ensued in the control room regarding the next actions to be taken. The inspectors heard someone ask whether entry into the AOPs was necessary, but heard no response. The inspectors observed that the test personnel remained at the C01 and CO2 main control boards, and continued to provide the test director with information ,

required by the test procedure. The on-shift operating crew did not appear to be taking any specific action in response to the unexpected, off-normal, condition. This was not consistent with the expectation, stated during the pre-job briefing, that the crew would take command of the unit during any off-normal event. After some time had passed, the inspectors asked the test director why the operators had not yet entered the AOP for a loss of power to safety-related buses. The on-shift crew took command of the control boards and entered the appropriate AOPs shortly thereafte r

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The total time elapsed between loss of power to 2A-05/2B-03 and its restoration was 69 minutes. The crew ultimately decided that the G-02 output breaker was in a

" tripped-free" state that could only be reset by taking the control switch back to

" pull-to-lock." The test crew, under the direction of the on-shift DSS, re-pu, formed the step in ORT 3A that specified taking the breaker to " pull-to-lock." This time the G-01 output breaker closed when it was retumed to the " auto" position. The test crew then completed ORT 3 The inspectors observed that the control room operators were appropriately deliberative in reviewing the available options, and the potential consequences for each option, in response to the loss of power to the safety-related buses. There was also adequate staffing of the control room to allow the operating crew to respond to the situation while support personnel reviewed the applicable technical specifications and evaluated reportability. On the other hand, the on-shift operating crew's delay in exiting the test procedure and entering tne applicable AOP (given the absence of contingency instructions in the ORT) was a concern to the inspectors. A second concern was that the DSS became actively involved in responding to the loss of power. This was not consistent with the licensee's expectations for the conduct of operations. Specifically, the inspectors understood that the DSS's resnonsibility was to monitor the performance of the operating supervisor and the duty operating supervisor, as well as the control board operators. Rather than maintaining this " big picture" role, the DSS appeared to be assuming the responsibilities of the operating superviso The inspectors were also concerned that re-energization of the buses appeared to be slowed by a partial focus on completing the ORT 3A test. Plant operators had restored power to de-energized "B" train safety-related buses on two units following a surveillance test related problem on July 7,1997 (LER 50-266/97034; 50-301/97034).

During the 1997 event. the inspectors had observed that the focus of control room operators was clearly on restoring power to the affected buses. Considerations associated with the test being performed at the time did not contribute to a delay in restoring power to be affected buses. During the 1999 event, the inspectors concluded that the operators' focus was, in part, on completing the ORT 3A test. In both the 1997 and 1999 cases, the epaiators were appropriately deliberative in ensuring that actions being taken were not going to create more significant safety problems. This necessary deliberativeness was not a concern to the inspectors. The licensee subsequently determined that the test coordinator, a non-licensed individual, contributed to the mixed focus on the part of the crew. This conclusion was consistent with the inspectors'

observation The " tripped-free" problem with the emergency diesel generator output breaker was well known to the licensee. A modification initiated in 1995 was designed to address this issue. The modification had been scheduled for completion prior to the performance of ORT 3A, however, it had been delayed. The modification was subsequently completed prior to unit restar ORT 3B The inspectors observed the performance of ORT 3B, " Safety injection with Loss of Engineered Safeguards AC (Train B)," on February 12,1999. The pre-job brief for this

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surveillance test addressed correc+ive actions for the loss of power experienced during performance of ORT 3A. Performance of ORT 3B was characterized by the same high quality communication techniques observed during performance of ORT 3A. All equipment worked as expected, and all acceptance criteria were satisfio ORT 3C February 9,1999, The inspectors observed the performance of ORT 3C, " Auxiliary Feedwater System and AMSAC { anticipated transient without SCRAM mitigating system actuation circuit] Actuation Unit 2," Original Revision. This ORT tested the automatic response of the AFW system in response to a steam generator low-low levelindication; automatic response of the AFW system in response to a low AFW pump suction pressure condition; automatic operation of the AFW system following an AMSAC signal; automatic steam generator blowdown isolation in response to an AFW pump start; and valve closure inhibit circuitry for AFW pump discharge pressure control valve The inspectors observed the conduct of the AFW system testing from the control roo The test director (a senior reactor operator) conducted a thorough pre-job briefing which clearly identified individual responsibilities for the test and contingency plans in the event of abnormal occurrence During the conduct of the test, a reactor operator noted that the discharge pressure control valve for the "B" AFW pump was slow to open compared to the equivalent valve for the "A" pump. The operator conveyed this observation to control room supervision who subsequently timed the valves opening during a later portion of the test and ultimately declared the affected valve (AF 4019) and thus, Train "B" of the AFW system, inoperable pending resolution of the slow valve opening times. A later engineering evaluation reveale'd thrd the valve performed within acceptable criteria for the train to perform its intended safety function; however, a good example of questioning attitude and conservative decision-raaking was illustrated by the operations test crew in identifying the potential proble As the test progressed other problems were encountered involving the "B" steam generator supply valve to the Unit 2 steam-driven AFW pump. This problem, compounded with the concerns with the operability of the Train "B" AFW, led the test director to abort the test. A plan was established and appropriately implemented which ended the testin The test was re-conducted on February 13,1999, no problems were encountered and all equipment performed satisfactoril c. Conclusions Routine portions of two major refueling outage frequency surveillance tests were conducted well. All safety-related equipment functional requirements were satisfie Operators displayed good questioning attitude regarding the performance of safety

, system valves, and the operations test director suspended the testing activity during a

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During a portion of one test, operators failed to promptly enter applicable AOPs following an unanticipated loss of power to safety-related buses. Operator response to '

the loss of power was impacted by conflicting focuses on recovering the buses and completing the test. The DSS became involved in solving the power problem rather 1 than maintaining the aloof oversight position expected by the license '

l M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Unit 2 Refuelina Outaae Modifications and Repairs The licensee completed many important to safety modifications during the 1999 Unit 2 i

refueling outage. Examples included reactor vessel baffle bolt replacement, main

! control board wire separation, and over-pressure protection for containment l penetrations and motor-operated va!ves.

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The inspectors also reviewed all 23 main control room work order stickers for Unit 2 on February 14,1999. Each work order had been screened for safety significance within the licensee's work order process. The inspectors did not identify any condition which should have been corrected prior to start-up. Notwithstanding the lack of safety significance, the fact that the licensee exited a major refueling outage with open control i room instrumentation work orders written over a year ago illustrated the magnitude of 1 the corrective and preventive maintenance backlog and necessary modification work at i the facilit I I

M2.2 Conduct of Maintenance durina the Refuelina Ontaae i Insoection Scope (IP 61726. 71707. & 62707)

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The inspectors observed the performance of various maintenance and surveillance test activities, and monitored the status of plant equipment during the post-maintenance

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testing performed near the end of the Unit 2 refueling outag !

l l b .- Observations and Findinas j Several equipment problems were experienced during post-maintenance testing and periodic surveillance testing of Unit 2 equipment. Examples included repeat bearing failures of the "B" train safety injection pump (2P-158) motor, failure of the "A" train safety injection pump (2P-15A) seal, and failures of safety-related valves (SI-897 and SI-857).

l An additional problem encountered during Unit 2 start-up preparations was associated with the nonsafety-related CVCS. A cleaning rag left in the CVCS system during maintenance work caused a water hammer transient when it became lodged in, and then passed through, a flow orifice. Most of the rag was retrieved from the seat area of I a CVCS valve downstream of the flow orifice. The licensee performed extensive system

. flushes and diagnostic tests to identify any other problems associated with this foreign L material. An extensive review of the potentialimpacts of any remaining pieces of rag were also performed. The licensee ultimately concluded that any remaining rag pieces 16 l

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would not affect the safe operation of the plant. The inspectors considered the licensee's evaluation to be thorough. However, the event illustrated potential weaknesses in the implementation of foreign material exclusion program requirements j and the rigor applied to contract worker oversigh The licensee initiated a root cause evaluation for the foreign material in the CVCS j system, and was evaluating a common cause evaluation for the increased failure of ;

j safety-related equipment following maintenance activitie I Conclusions -

There were several examples of safety-related equipment that failed post-maintenance l testing and periodic surveillance tests and an instance where foreign material (pieces of I a cloth rag) was left in the reactor coolant system after maintenance activities and l caused a minor water hammer in the chemical and volume control system. The l maintenance-related problems were more significant than those observed during l previous outage M8 Miscellaneous Maintenance issues

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M8.1 (Closed) LER 50-266/98010-00 and 50-266/98010-01: 50-301/98010-00 and 50-301/98010-01: Inadequate Technical Specifications Surveillance of Containment

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l Spray Logic. On February 13,1998, the licensee identified that portions of the containment spray logic circuits were not being tested on a quarterly frequency in accordance with T/S Table 15.4.1-1, item 27, " Containment Pressure These logic j circuits were subsequently tested with satisfactory results. The inspectors verified the l

corrective actions described in the LER were completed by the licensee. The failure to !

perform quarterly testing of portions of the containment spray logic circuits constituted a violation of T/S 15.4.1, which required the circuits be tested quarterly. This j non-repetitive, licensee-identified and corrected violation is being treated as an NCV in i accordance with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-266/99002-03(DRP); 50-301/99002-03(DRP)).

l l Ill. Enaineerina E1 Conduct of Engineering .

E Enaineerina Deoartment Resoonse to Continuina Lubrication Control Issues

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I Insoection Scope (IPs 37551 & 40500)

The inspectors reviewed the licensee's efforts in addressing continuing problems with l

the control of lubricants. This review included an assessment of the licensee's corrective action .

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i b. Observations and Findinas l

.I,ubrication Control Problems An inspector review of condition reports revealed that the licensee had documented several occurrences of improper lubricants being used for safety-related equipment in 1998. Each reported occurrences was evaluated and either the correct lubricant was subsequently used or an engineering evaluation was performed to verify that the incorrect lubricant was acceptable for use on the affected component. The reported i uses of incorrect lubricants were dealt with on an individual basis; however, no broad j scope assessment of the lubricant control program was initiated by the license l l

a On December 27,1998, a condition report was written identifying discrepancies i between the computer database equipment listings of lubricants and the licensee's i lubrication manual. The specific discrepancy referenced in the condition report j pertained to oil for the Unit 1 and 2 emergency diesel generator governors. On '

December 30, the wrong lubricant was added to the Unit 2 emergency diesel generator governor. At the daily manager's meeting conducted the same day, the Site Vice President requested that a root cause evaluation be performed to assess the lubrication control problem at the statio The lubrication manual contents were compared to the information contained in the station equipment database. Some discrepancies were identified during the licensee's review; however, none of the problems affected equipment operability. The licensee and the inspectors concluded that the licensee had not previously assessed the programmatic implications of the lubrication control problems until numerous errors had occurre Lack of Enaineerina Review Thorouahness As part of the root cause evaluation, the licensee identified that the environmental qualification maintenance requirements for lubricants on some safety-related motors had not been met. This issue dealt with service life of lubricants in sealed-for-life i i

bearings in safety-related applications such as the residual heat removal system pump motors. The inspectors were concerned that this issue was not recognized earlier. It had been previously discussed by the resident inspectors with the responsible engineer ;

in April 1998 (IR 50-266/98005(DRP); 50-301/98005(DRP), issued May 5,1998). Based !

on the content of licensee documents from May 1998, the inspectors believed that more rigorous follow-up or more effective communications between the component  ;

engineering group and the environmental qualification engineering group would have l'

resulted in a more timely resolution of the potential proble Based on the specific circumstances of this condition, the inspectors concluded that it represented a weakness within the licensee's engineering organization rather than a regulatory non-compliance. At the time of the inspection, the lubrication issues appeared to be receiving appropriate attention within the licensee's corrective action progra l ('

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p l Conclusions The licensee was slow to recognize generic weaknesses in the programs for controlling the use of lubricants in safety-related applications. Examples of the problems included i inconsistencies in various licensee documents, and poor follow-through by engineering I staff or poor communications between engineering groups when addressing lubrication issue E2 Engineering Support of Facilities and Equipment E2.1 Load Evaluation for Unit 2 480-Volt Safetv-Related Bus 28-03 and 2B-04 Crosstie l Insoection Scope (IP 37551)

The inspectors reviewed the licensee's evaluation of the cross-connection of the Unit 2 480-volt safety-related buses,2B-03 and 2B-0 Observations and Findinos The licensee de-energized the Unit 2 4160-volt safety-related bus 2A-05 for modification and cleaning during the Unit 2 refue;ing outage. To power the 480-volt safety-related bus 28-03 loads, which were normally supplied from 2A-05, the licensee cross-tied

, 28-03 with another 480-volt safety-related bus (28-04). Section B.1.e.1 of T/S 15.3.7,

" Auxiliary Electrical Systems," required the licensee to perform an evaluation to show that the loads that remained or could be energized by the buses would not cause a potential overload of the associated diesel generato The licensee performed Calculation Number 98-0111, "480 Volt Bus 2803,2B04 Tie Loading Analysis," Revision 0, to satisfy the T/S. In addition to evaluating diesel generator loading, the calculation also evaluated the potential loading upon the buses, transformers, and cabling, as well as protective device settings. The calculations were well documented and thorough. The inspectors independently verified portions of the licensee's assumptions and determined them to be appropriat Calculation 98-0111 determined certain restrictions on plant configuration would be required if buses 28-03 and 2B-04 were to be cross-tied. The restrictions included removal from service of one service water pump supplied from the cross-tied buses and not allowing the diesel generator that was aligned to automatically provide power to the 1 cross-tied buses to be aligned to supply any Unit 1 safeguards bus. The inspectors !

verified the licensee properly implemented these restrictions when 28-03 and 2B-04 I were cross-tie I Conclusions The inspectors determined that the licensee's evaluation to cross-tie safety-related l 480-volt buses was thorough and well documented. Equipment configuration restrictions specified in the evaluation were verified by the inspectors to have been properly implemented by the license i

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l l E7 Quality Assurance (QA)in Engineering Activities

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E QA Audit of Station-wide Corrective Action Proaram (IPs 37551 & 40500)

1 l The inspectors attended a GA exit meeting held on February 5,1999, which presented results of a completed audit of the station's operating experience, vendor technical !

information, and corrective action programs. The inspectors noted that the depth and breadth of the audit was sufficient to identify strengths and deficiencies within the audited programs. The operating experience and vendor technicalinformation  ;

programs were found to be adequately implemented with areas for improvement l identified. The corrective action program was determined to be adequate; however, I many areas warranted further management attention, including thoroughness of root cause evaluations, timeliness of corrective actions, and effective trending of reported problems. Many of the findings were similar to those identified by the inspectors in past ,

irs. A further review of the corrective action program is documented in l IR 50-266/99005(DRS); 50-301/99005(DRS).

E8 Miscellaneous Engineering issues 1 E (Closed) eel 50-266/96018-07d: 50-301/96018-07d: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure from April 1993 to February 1997 to correct a condition adverse to quality where i the 1P-15B safety injection pump, powered from a lightly loaded emergency diesel generator with speed droop set, would run at higher frequency and current, potentially tripping on overcurrent. The licensee subsequently modified the G01 and G02 diesels l (in July 1997 and February 1998, respectively) to replace the hydro-mechanical j governor with the speed droop feature, thereby eliminating the potential for elevated j frequency operation of the safety injection pump motor. The licensee's other diesels, ;

G03 and G04, had already been provided with an electronic load-sharing governor (no speed droop) to ensure operation at the nominal frequency of 60 hertz under all operating conditions. Since the modification of the G01 and G02 diesels, the safety injection pump has not tripped because of overcurrent during surveillance testin E8.2 (Closed) eel 50-266/96018-07e: 50-301/96018-07e: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure until December 16,1996, to perform an assessment of the condition identified on December 22,1994, where backup reactor trip circuits did not meet safety-related train separation requirements, possibly affecting those circuits during postulated single-failure events. As discussed in the licensee's response to this issue, the FSAR was revised to include the technical justification for not meeting the separation requirements. In addition, as with the other examples of the corrective action escalated enforcement items from IR 50-266/96018; 50-301/96018 discussed in Sections 08 and E8 of the current inspection report, the licensee has discussed with the appropriate plant staff the need to take prompt, comprehensive corrective actions when conditions adverse to quality are identifie l E8.3 (Closedl eel 50-266/96018-070: 50-301/96018-07a: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the j failure until December 19,1996, to perform an assessment of the condition identified on l

December 16,1994, where instruments of lesser accuracy than original margins had accounted for may have resulted in nonconservative T/S setpoints for five reactor protection system trip parameters. The licensee subsequently determined in its evaluation that the trip parameters were within the required limits considering instrument accurac E (Closed) eel 50-266/96018-07h: 50-301/96018-07h: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure until Decembcr 16,1996, to assess a condition adverse to quality identified in January 1996, where nonconservative operation of the containment condensate measuring system may have resulted in the inability to detect a one gallon per minute leak of reactor coolant within four hours. The inability to measure this leak rate was contrary to the licensee's response to NRC Generic Letter 84-04, "SE of Westinghouse Topical Reports Dealing with the Elimination of Postulated Pipe Brenks in PWR Primary Main Loops." The licensee subsequently determined in its evaluation that the condensate measuring system performance capability was within the specified limits and that the system fulfilled the requirement of T/S 15.3.1.D.7 as a reactor coolant leak detection syste E8.5 (Closed) eel 50-266/96018-07i: 50-301/96018-07i: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI," Corrective Action," for the failure until December 16,1996, to assess a condition adverse to quality identified in January 1996, where replacement backdraft dampers for containment fan coolers may have only been analyzed for static conditions and not for the dynamic forces following a loss-of-coolant accident (LOCA). From an evaluation of the original Bechtel design documents, the FSAR, and the inplant system configuration, Sargent and Lundy determined for the ,

licensee that the backdraft dampers would not be damaged during a LOC I E8.6 (Closed) eel 50-266/96018-07i: 50-301/96018-07i: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure until December 11,1996, to assess a condition adverse to quality identified in January 1995, where original Bechtel design calculations lacked evidence that the seismic analysis for containment was considered in the design for the shield walls and intermediate concrete slabs and support steel. A subsequent evaluation (Calculation 10447-9611-001) of containment internal structures for seismic loads by Bechtel, the original plant architect, indicated that seismic loads did not govern containment floor design; that the primary and secondary shield walls were adequate for shears, bending moments, and axial loads from the containment seismic analysis; and that the connections between the secondary shield walls and the containment floor slabs were adequate to transfer floor slab horizontal loads, with vertical seismic loads being carried by the structural steel supporting the slab i E (Closed) eel 50-266/96018-07k: 50-301/96018-07k: An example of an apparent i violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the l failure until December 13,1996, to assess a condition adverse to quality identified in Apnl 1995, where main feedwater flow would be lost immediately during a small-break ;

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LOCA accident instead of after two seconds as assumed in accident analyses. The licensee's evaluation included an assessment by the reactor vendor that the effect of minimum versus maximum main feedwater system isolation delays usually had only a small effect on the computed peak clad temperature parameter of concern in small-break LOCA analyse E8.8 (Closed) eel 50-266/96018-071: 50-301/96018-071: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action,' for the failure until l

December 13,1996, to assess a condition acverse to quality identified in March 1993, where the fault currents for five safety-related 480-volt motor control centers could potentially be larger than the interrupting capability of the breakers. This issue was subsequently pursued by the licensee as a 10 CFR Part 50, Appendix R concern, for which LER 50-266/97-032; 50-301/97-032 was issued. The LER was subsequently closed by the NRC and the issue of inadequate interrupting capability is currently being tracked as eel 50-266/97022-02; 50-301/97022-0 E8.9 (Closed) eel 50-266/96018-07m: 50-301/96018-07m: An example of an apparent violation of 10 CFR Par 150, Appendix B, Criterion XVI, " Corrective Action," for the failure on or around June 14,1995, to correct T/S Table 15.3.5-1 when the licensee identified that proposed loss-of-voltage relay settings (which were subsequently incorporated into the Table) were nonconservative. The licensee had identified one low probability scenario in which there might be a lack of breaker coordination between 4160-volt and 480-volt breakers with an emergency diesel generator operating. Instead of changing the T/S, the licensee opted to change the relays to resolve the issue, completing the last of the modifications during the recently completed Unit 2 refueling outag E8.10 (Closed) eel 50-266/96018-07n: 50-301/96018-07n: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure to properly correct an NRC-identified error in a calculation for the loss-of-voltage relays. The licensee revised the calculation to correct error and counseled the individual involved in the error on the need for conservative decision-making and for attention-to-detai E8.11 (Closed) eel 50-266/96018-07a: 50-301/96018-07a: An example of an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, " Corrective Action," for the failure from October 14,1996, to January 9,1997, to test two Unit 1 spare containment penetrations that the licensee identified on October 14 as not having been tested since 1995. The testing of the penetrations was reviewed as part of the NRC closecut of LER 50-266/97002; 50-301/97002 in IR 50-266/98009(DRP); 50-301/98009(DRP). The need for taking prompt corrective actions has been emphasized to plant staff by station management. Inspections during the latter half of 1997 and in 1998 have indicated a significant improvement in the licensee's identification and correction of issues.

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I l IV. Plant Suonort I

R1 Radiological Protection and Chemistry (RP&C) Controls I

Throughout the inspection period, the inspectors observed radiological control postings and radiation protection technician performance during tours of the radiologically controlled area, including Unit 2 containment. All postings and surveys for radiological areas were appropriate and current, and technicians provided appropriate radiological i oversight of work activitie V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 22,1999. The licensee acknowledged the findings presente )

l The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie l

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A PARTIAL LIST OF PERSONS CONTACTED

Licensee

' Wisconsin Electric Power Comospny C. R. Peterson, Director of Engineering D. P. McCloskey, Maintenance Manager J. G. Schweitzer,' System Engineering Manager J. R. Anderson, Operations Manager M. E. Reddemann, Site Vice President

. R. G. Mende, Plant Manager

. R. P. Farrell, Radiation Protection Manger V. M. Kaminskas, Regulatory Services and Licensing Manager

NRC

. B.A. Wetzel, Point Beach Project Manager, NRR

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p INSPECTION PROCEDURES USED l

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IP 37551: Onsite Engineering l IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing l Problems '

IP 60855: Operation of an ISFSI  ;

IP 61726: Surveillance Observations l IP 62707: Maintenance Observations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92901: Followup - Operations i IP 92902: Followup - Maintenance l IP 92903: Followup - Engineering IP 92904: Followup - Plant Support ITEMS OPENED, CLOSED, AND DISCUSSED

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l Opened 50-266/99002-01a(DRP) VIO AOP and EOP use and implementation 50-301/99002-01a(DRP)

50-266/99002-01b(DRP) VIO AOP and EOP use and implementation 50-301/99002-01b(DRP)

50-301/99002-02(DRP) NCV Operation of the Unit 2 reactor core at an actual average reactor power of 1519.1 megawatts thermal for an eight-hour shift

50-266/99002-03(DRP) NCV Failure to perform quarterly testing of portions of 50-301/99002-03(DRP) containment spray logic circuits Closed 50-266/97039-00 LER Residual heal removal loop inoperable due to an inoperable component cooling water pump 50-301/98004 LER Plant operation with reactor core power level in excess of 1518.5 megawatts thermal 50-301/99002-02(DRP) NCV Operation of the Unit 2 reactor core at an actual average reactor power of 1519.1 megawatts thermal for an eight-hour shift l

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50-266/98021-02(D"P) URI immediate operator actions 50-301/98021-02(DRP)

50-266/99002-014.(DRP) VIO AOP and EOP use and implementation 50-301/90002-01a(DRP)

50-266/99002-01b(DRP) VIO AOP and EOP use and implementation 50-301/99002-01b(DRP)

50-266/96018-07(DRP) eel Appendix B, Criterion XVI problems 50-301/96018-07(DRP)

(allitems except 07o)

50-266/98010-00,01 LER Inadequate Technical Specification surveillance 50-301/98010-00,01 of containment spray logic 50-266/99002-03(DRP) NCV Failure to perform quarterly testing of portions of 50-301/99002-03(DRP) the con @nent spray logic circuits 50-201/97016-03(DRP) IFl- Water hammer in the Unit 2 auxiliary feedwater system Discussed .

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50-266/97022-02(DRP) eel Secondary fire potential created by inadequate 50-310/97022-02(DRP) breaker capability

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LIST OF ACRONYMS USED AFVJ Auxiliary Feedwater AOP Abnormal Operating Procedure CFR Code of Federal Regulations CR Condition Report DRP Division of Reactor Projects DRS Division of Reactor Safety DSS- Duty Shift Superintendent EOP . Emergency Operating Procedure FSAR Final Safety Analysis Report IFl Inspection Followup Item IP inspection Procedure IR inspection Report LER Licensca Event Report LOCA Loss-of-Coolant Accident MWT Megawatts Thermal NC Non-Cited Violation NRC Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation OD Operability Determination OM Operations Manua OP Operating Procedure ORT Operations Refueling Test PDR Public Document Room .

PPCS Plant Process Computer System QA Quality Assurance ~

RCP Reactor Coolant Pump T/S _ Technical Specification URI Unresolved item ,

VIO Violation I

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