IR 05000271/1987023

Insp Rept 50-271/87-23 on 871222-880208.No Violations Noted. Major Areas Inspected:Licensee Action on Previous Insp Findings,Operational Safety,Physical Security,Surveillance Activities,Lers,Operational Events & Maint Activities

ML20147D692
Person / Time
Site:	Vermont Yankee
Issue date:	02/26/1988
From:	Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20147D685	List: IR 05000271/1987023 ML20147D682
References
50-271-87-23, IEB-79-24, IEB-87-002, IEB-87-2, NUDOCS 8803040096
Download: ML20147D692 (19)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Report-No.:- 50-271/87-23 Docket No.: 50-271 License No. DPR-28 Licensee: Vermont Yankee Nuclear Power Corporation RD 5, Box 169 Brattleboro, Vermont 05301 Facility: Vermont Yankee Nuclear Power Station Inspection At: Vernon, Vermont Inspection Conducted: December 22, 1987 - February 8, 1988 Inspectors: Geoffrey E. Grant, Senior Resident Inspector John B. Macdonald, Resident Inspector Approved By: sN$ w . 2hb JAV

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Donald R. Haverkamp, Chie,ff Date Reactor Projects Section No. 3C Inspection Summary: Inspection on December 22, 1987 - February 8, 1988

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(Report No. 50-271/87-23)

Areas Inspected: Routine onsite regular and backshift inspection by two resident inspectors (183 hours0.00212 days <br />0.0508 hours <br />3.025794e-4 weeks <br />6.96315e-5 months <br />). Areas inspected included licensee action on previous inspection findings, operational safety, physical security, surveil-lance activities, licensee event reports, operational events, maintenance activities, licensee response to NRC initiatives, and periodic and special report Results: No unacceptable conditions were identifie Deficiencies in the implementation of the surveillance test program resulted in two missed tech-nical specification required surveillance Although apparently an anomalous occurrence, these deficiencies illuminated several overall program weaknesse The controlling procedure lacks definitive requirements and does not encompass the concept of independent quality review. Failure to ensure proper qualifica-tion of the new surveillance testing coordinator was a management deficiency (see Section 6.0). The licensee lacks a programmatic approach to cold weather operations. Separate and diverse freezing related problems demonstrated the ineffectiveness of an informally controlled program. Repetitive failures of the reactor building ventilation system due to air line free;:ing demonstrated an initial inability to identify the root cause and take effective corrective action (see Section 9.0). The licensee exhibited strong management involvement and quality control during the preparations for and repositioning of the con-trol rod blade storage rack within the spent fuel (see Section 9.1).

8003040096 300226 PDR ADOCK 05000271 Q PDR

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TABLE OF CONTENTS

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PAGE Persons Contacted. . . . . . . . . . . . . . . . . . . . . . . 1 Summary of Facility and NRC Activities . . . . . . . . . . . . 1 Licensee Action on Previous Findings (IP 92701)* . . . . . . . 1 3.1 (Closed) Unresolved Item 85-14-06: Alternate Testing Surveillance of Diesel Generators . . . . . . . . . . . . 1 3.2 (Closed) Follow Item 85-20-07: FEMA Test of Public Notification System . . . . . . . . . . . . . . . . . . . 2 Operational Safety (IP 71707, 71710) . . . . . . . . . . . . . 2 4.1 Plant Operations Review . . . . . . . . . . . . . . . . . 2 4 . 7. Safety System Review. . . . . . . . . . . . . . . . . . . 3 4.3 Feedwater Leak Detection System Status. . . . . . . . . . 3 4.4 Inoperable Equipment. .................. 3 4.5 Review of Lif ted Leads, Jumpers and Mechanical Bypasses. . . . . . . . . . . . . . . . . . . . . . . . . 4 4.6 Review of Switching and Tagging Operations. . . . . . . . 5 4.7 Operational Safety Findings . . . . . . . . . . . . . . . 5 Physical Securi ty (IP 71707) . . . . . . . . . . . . . . . . . 5 5.1 Security Observations . . . . . . . ... . . . . . . . . . 5 5.2 Security Events Review. . . . . . . . . . . . . . . . . . 6 5.3 Security Event Reports. . . . . . . . . . . . . . . . . . 6 Surveillance Activities (IP 61726, 90712). . . . . . . . . . . 6 Licertee Event Reports (IP 92700). . . . . . . . . . . . . . . 8 Operational Events (IP 71707, 71710, 62703). . . . . . . . . . 8 8.1 HPCI and RCIC Inoperability . .............. 8 8.2 ADS By-pass Switch Annunciator Ground . . . . . . . . . . 9 Maintenance Activities (IP 62703, 71714) . . . . . . . . . . . 10 9.1 Control Rod Blade Rack Assembly Repositioning . . . . . . 10 9.2 Condensate Storage Tank Instrument Line Leak. . . . . . . 11 9.3 Reactor Building HVAC Isolations. . . . . . . . . . . . 12 9.4 Preparations for Cold Weather Operations. . . . . . . . . 13 1 Licensee Response to NRC Initiatives . . . . . . . . . . . . . 13 10.1 NRC Compliance Bulletin 87-02 (TI 2500/26). . . . . . . . 13 10.2 OB Breaker Mechanical Trip Mechanisms (IP 93702). . . . . 15 11. Periodic and Special Reports (IP 90713). . . . . . . . . . . . 16 12. Management Meetings (IP 30703) . . . . . . . . . . . . . . . . 16 ,

Attachment A - Event at an operating power reactor

• The NRC Inspection Manual inspection procedure (IP) or temporary instruction (TI) or the Region I temporary instruction (RITI) that was used as inspection guidance is listed for each applicable report section, i ,

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DETAILS Persons Contacted Interviews and discussions were conducted with membeis of the licensee staff and management during the report period to obtain information per-tinent to the areas inspecte Inspection findings were discussed periodically with the management and supervisory personnel listed belo Mr. P. Donnelly, Maintenance Superintendent

• Mr. R. Grippardi, Quality Assurance Supervisor

• Mr. S. Jefferson, Assistant to the Plant Manager Mr. G. Johnson, Operations Supervisor Mr. R. Lopriore, Maintenance Supervisor

• Mr. R. Pagodin, Technical Services Superintendent

• Mr. J. Pelletier, Plant Manager Mr. R. Wanczyk, Operations Superintendent Mr. T. Watson, ! & C Supervisor

• Attendee at post-inspection exit meeting conducted on February 19, 1988 2. Summary of Facility and NRC Activities Vermont Yankee Nuclear Power Station continued full power operations dur-ing this period except for pre-planned power reductions to accomplish required surveillances and a rod pattern exchange. The period was note-worthy for sub-zero weather which caused a number of freeze-related prob-lems at the plant including cracking and subsequent leakage of a conden-sate storage tank instrument flush line (see Section 9.2) and multiple failures of the reactor building ventilation system (see Section 9.3).

An NRC operator licensing examination was conducted during the period of January 19-20, 1988 (Inspection Report 88-01). An NRC Region I specialist inspector completed a routine review of radiological controls during the period of February 1-5, 1988 (Inspection Report 88-02).

During the period of January 10-15, 1988, the Senior Resident Inspector participated in an NRC Region I operationally-oriented team inspection at the Yankee Nuclear Power Station in Rowe, Massachusett . Licensee Action on Previous Inspection Findings 3.1 (Closed) Unresolved Item 85-14-06: Alternate Testing Surveillance of Diesel Generators: The original concern was the timing, priority and timeliness of alternate testing of various safety related components per technical specification (TS) 4.5.H when one diesel generator is inoperabl The inspector then noted that the licensee policy regarding alternate testing did not appetr to meet the intent of TS 4.5.H as it related to the TS definition 1.0.D of "immediate". The

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licensee initial assessment of this item was documented in a July 25, 1985 memorandum from the operations department to the Assessment Coordinator. The conclusions in this memo were non-responsive to the inspector's concerns. A subsequent memorandum from the Operations Supervisor to the Assessment Coordinator dated January 13, 1987 revised the licensee position on this issu Procedure AP 0025, "Plant Equipment Control" was modified to include amplifying information to the shift supervisor concerning alternate testing. No instances similar to this have been observe This item is close .2 (Closed) Follow Item 85-20-07: FEMA Test of Public Notification System. The licensee conductec a test of the Public Notification System (PNS) on June 27, 1985 as part of an evaluation by the Federal Emergency Management Agency (FEMA). The test consisted of activating both the NOAA Alert radios and sirens in selected communities, followed by a telephone survey by FEH The test also included activation of the Emergency Broadcast networks in Vermont, New .

Hampshire and Massachusetts. The inspector noted no deficiencies reported by FEM This item is close . Operational Safety 4.1 Plant Operations Review The inspector observed plant operattuns during regular and backsh' ft tours of the following areas:

Control Room Cable Vault Reactor Butiding Fence Line (Protected Area)

i Diesel Generator Rooms Intake Structure l Vital Switchgear Room Turbine Building l

Control Room instruments were observed for correlation between

! channels, proper functioning, and conformance with Technical Specifi-cations. Alarm conditions in effect and alarms received in the con-trol room were reviewed and discussed with the operators. Operator awareness and response to these conditions were reviewed. Operators were found cognizant of board and plant conditions. Control room and shif t manning were compared with Technicsl Specification require-ment Posting and control of radiation, contaminated and high radiation areas were inspected. Use of and compliance with Radiation Work Permits and use of required personnel monitoring devices were checked. Plant housekeeping controls were observed including control of flammable and other hazardous materials. During plant tours, logs and records were reviewed to ensure compliance with station proced-ures, to determine if entries were correctly made, and to verify

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correct communication of equipment statu These records included various operating logs, turnover sheets, tagout and jumper logs, and Potential Reportable Occurence Reports. Inspections of the control room were performed on weekends and backshifts including December.22-24, 27, 29, 1987, January 4-7, 10, 15, 18-22, 25, 27-28, February 1-4, 198 Operators and shift supervisors were alert, attentive and responded appropriately to annunciators and plant condition No violations or safety concerns were identifie .2 Safety System Review The emergency diesel generators, residual heat removal, core spray, residual heat removal service water, high pressure coolant injection, and reactor core isolation cooling systems, were reviewed to verify proper alignment and operational status in the standby mod The review included verification that (1) accessible major flow path valves were correctly positioned; (ii) power supplies were energized, (iii) lubrication and component cooling was proper, and (iv) compo-nents were operable based on a visual inspection of equipment for .

leakage and general conditions. No violations or safety concerns were identifie .3 Feedvater Leak Detection System Status The inspector reviewed the feedwater leakage detection system and the monthly performance summary provided by the licensee in accordance with letter VYNPC letter FVY 82-105. The licensee reported that, based on the leakage monitoring data reduced as of December 31, 1987, there were no deviations in excess of 0.10 from the steady state value of normalized thermocouple readings, and no failures in the 16 thermocouples installed on the four feedwater nozzle Point number 12, which had previously showed a downward (cooling) trend (see Inspection Report No. 50-271/87-21, Section 4.2), did not continue to exhibit increased cooling during this evaluation period. The current value for this thermocouple is not unusually low when compared to previous cycle readings. The licensee is closely monitoring this thermocouple for further trends and will complete an assessment dur-ing the current evaluation perio The inspector had no further questions in this are .4 Inoperable Equipment Actions taken by plant personnel during periods when equipment was 1 inoperable were reviewed to verify: technical specification limits were met; alternate surveillance testing was completed satisfactor-ily; and, equipment return to service upon completion of repairs was proper. This review was completed for the following items:

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January 12,1988--Reactor core isolation cooling system (RCIC) was declared inoperable in order to perform troubleshooting on RCIC flow controller FIC-13-91. Flow indication had been observed to be cycling continuously when the system was secured in a no flow con-ditio .;efer to Section 8.1 for more detai Januecy 14, 1988--High pressure coolant injection (HPCI) was declared inopirable to repair the failed gland seal vacuum pum Refer to Section 8.1 for more detai January 14, 1988--RCIC was declared inoperable to replace the manual ise tation valve for pressure switch PS-13-87 The valve had failed to close. Refer to Section 8.1 for more detai January 14, 1988--RCIC was declared inoperable a second time when IST vibration test data results indicated that monitoring point Z-2 was in the required action rang Refer to Section 8.1 for more detai The reactor building ventilation system isolated and tripped on <

numerous occasions beginning on January 10, 198 The isolations apptar to be caused by freezing of the instrument air lines to the ventilation dampers allowing them to drift close Refer to Section 9.3 for more detai Both trains of the toxic gas monitoring (TGM) system continued to be out of service individually and simultaneously during the inspection perio No violations or deviations were identifie .5 Review of Lifted Leads, Jumpers and Mechanical Bypasses Lifted leads and jumper (LL/J) requests and mechanical bypasses (MB)

were reviewed to verify that controls established by AP 0020 were met, .$o conflict with the technical specifications were created, the requests were properly approved prior to installation, and a safety evaluation in accordance with 10 CFR 50.59 was prepared if require Implementition of the requests was reviewed on a sampling basi The LL/J 80-001 authorized January 5,1988, was issued to eliminate a 35V grounsi located between the automatic depressurization system (ADS) inhibit switch and the ADS annunciator. The LL/J implementa-tion caused a loss of the ADS inhibit switch status annunciato Therefore, status indication of the ADS inhibit switch was ensured by controlling the switch key (disengaged beside it) and verifying its presence on the control room operator turnover sheets. Refer to Section 8.2 for more detai _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ .

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.The LL/J 88-002 authorized January 5, 1988 was issued to maintain the-circulating water bay south louvers closed during winter operation ' Refer to Section 9.4 for more detai No violations or deviations were identifie .6 Review of Switching and Tagging Operations The switching and -tagging log was reviewed and tagging activities were inspected to verify plant equipment was controlled in accordance with - the requirerents of AP 0140, Vermont Local Control Switching Rule The follcwing switching and tagging orders were reviewed:

88-0008--issued on January 5,1988 to support the CST 11A pipe and heat tracing repair (MR 88-0003) (Section 9.2).

88-0032--issued on January 14, 1988 to support the HPCI gland seal vacuum pump maintenance (MR 88-0080) (Section 9.1).

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88-0053--issued on January 22, 1988 to isolate the second leak iden-tified on CST 11A (Secticn 9.2)

88-0063--issued to support the termination and capping of CST 11A (MR 88-0059) (Section 9.2).

No violations or deviations were identifie .7 Operational Safety Findings The licensee has initiated steps to limit the unavailability of the reactor building ventilation system and the TGM syste Two plant information report (PIR) teams have been commissioned to identify deficiencies and recommend corrective actions to increase system reliabilit Licensee administrative control of off normal system configurations by the use of LL/J, mechanical bypass, and switching and tagging procedures, as reviewed in Sections 4.5 and 4.6, was in complian e with procedural instructions and was consistent with plant safet . Physical Security 5.1 Security Observations Selected aspects of plant physical security were reviewed during regular and backshif t hours to verify that controls were in accord-ance with the security plan and approved procedure This review included the following security measures: guard staffing; vital and protected area barrier integrity; maintenance of isolation zones; and, implementation of access controls, including authorization, badging, escorting, and searche No inadequacies were identifie ,

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5.2 Security Events Review The inspector reviewed the licensee response actions for events that occurred from October 8,1987 through December 31, 1987. Prompt and adequate compensatory measures were taken during each event and main-tained for the duration of the haijware outag Fourteen events occurred during this perio None of these events were required to be reported under the newly implemented guidelines of 10 CFR 73.7 (a) or (b) (one hour repert to NRC Duty Officer). All events reviewed were minor in nature and easily correcte Licensee docu-mentation of these events was generally very good. No violations or safeguards concerns were identifie .3 Security Event Reports

- The inspector reviewed the fourteen security event reports that were generated during this period which described the above events. Addi-tionally, the security event log required by the newly implemented guidelines of 10 CFR 73.71 (c)(1) was reviewe The event reports accurately described the circumstantes of each incident and the licensee's follow-up actions. The inspector also reviewed the final close-out report for an event that occurred on September 18, 1987 (Licensee Security Event Report 87-18) and found the final (dispo-sition of issues and corrective actions to be acceptabl The

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inspector reviewed the security event documentation for the fourth

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quarter of 1987 submitted to the NRC pursuant to the new requirements of 10 CFR 73.71 (c)(2). This was the first report submitted by the licensee -under the new requirement Although the report provided l the required documentat.on, the depth of information was minimal.

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The licensee is reviewing this and seeking guidance from regional security specialist The inspector identified no inadequacie . Surveillance Activities The VYNPS TS Table 4.2.1 requires that the LPCI reactor vessel shroud level permissive for containment spray (CS) be functionally tested to ensure operability once per mont Contrary to the above the functional test of the LPCI reactor vessel shroud level permissive was not performed for the months of October and November 1987.

The missed TS surveillance was discovered on December 15, 1987 during an I

, & C departmental review of required surveillance testing. Upon recogni-

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tion of the missed surveillance, the license immediately completed the test satisfactorily on December 15, 198 .

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The root cause of this event appears to have been precipita'ted by se seral weaknesses within the surveillance program. Immediately, the surveillance test was missed when the procedural steps required to perform the surveil-lance were removed from an existing plant procedure OP 4337, "Reactor Water Level ECCS' Initiation Isolation" and were included in the initial revision of a new plant procedure OP 4336, "Containment Spray Low Water Level Interlock". Although the procedure revisions were implemented in September, the October 1987 monthly surveillance test schedule was issued incorrectly and referenced OP 4337 as the procedure to be performed to accomplish the functional test of this safety functio The subsequent monthly surveillance - test schedules issued for November and December perpetuated the erro It was not until December 15,1987 that an I&C individual personally involved with the procedure revisions identified the erro Identification of this error led to several other inspector concerns within the surveillance progra The surveillance testing coordinator (STC) had not been completely trained in the requirements of the position or in the implementation of the surveillance testing control procedure, c AP 400 Although this did not directly contribute to this event and complete training was immediately provided, it indicated a lack of manage-ment involvement in ensuring the administration of proper training. Fur-ther, AP 4000 had a procedural weakness in that positive acknowledgement of receipt and proper implementation of a change to a surveillance test schedule from the STC to the originating individual was not procedurally required. Such a mechanism, or a similar administrative control, could prevent future missed surveillance events, In general, the accountability developed in and descriptive instruction of AP 4000 appear inadequate to ensure full compliance with all surveillance program requirement Another concern involved the methodology for implementing surveillance testing. A yearly surveillance schedule is generated by the STC from the master surveillance list which includes the test number and title, the performing department, interval, due date, procedure reference, TS refer-ence if applicable, and required completion dates. The monthly surveil-lance schedule, with the same information included, is then generated from the yearly and distributed to the responsible department supervisors. It appears that at the departmental level the focus of ensuring that each TS surveillance requirement is satisfied is redirected to ensuring that each

, procedure that should include the surveillance requirement is performed.

l In the event above, the performing department was only ensuring that the l referenced procedure was completed as opposed to ensuring that the sur-i veillance requirement was satisfie The licensee is currently reviewing this issue.

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The final concern was that an independent review of the surveillance program to ensure that all surveillance requirements were identified, proper surveillance periodicities were assigned and surveillance proced-ures properly satisfied surveillance criteria was not required by the instruction of AP 400 After discussions with the inspectors, the licensee agreed to implement an independent review program. A second missed TS-required surveillance to test secondary containment isolation valves at a quarterly frequency was identified as a result of the initial review. The licensee has been developing a computer-based surveillance tracking ' program which should preclude recurrence of similar events. The system is scheduled to be implemented on a trial basis in the spring of 198 Because the initial missed TS surveillance event was identified by the licensee, was reported in LER 87-19, was of a low severity level, had prompt corrective actions taken which identified the second missed TS surveillance (to be reported in LER 87-19, Revision 1) and was not related to corrective actions for a previous violation, no notice of violation will be issued in this instance (50-271/87-23-01).

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7. Licensee Event Report The following Licensee Event Report was reviewed by the inspector: I LER 87-19, Missed Surveillance of LPCI Reactor Vessel Level Permissive Due '

to Personnel Error. This LER was submitted as a result of a missed TS surveillance as reported January 14, 198 The event, root cause and corrective actions, as described in the LER, are documented in detai1 in Section The inspector determined that: (1) the report was submitted in a timely manner; (2) description of the event presented was accurate; (3) root cause analysis was performed; (4) safety implications were considered; and (5) corrective actions implemented or planned were sufficient to preclude reccurrence of a similar event. No violations or reporting concerns were identifie . Operational Events 8.1 HPCI and RCIC Inoperability On January 12, 1988, at 10:25 a.m. , the RCIC system was declared inoperable to perform troubleshooting on RCIC flow controller l FIC-13-91. Flow indication had been cycling continually under no-l flow conditions when the system was secured. Troubleshooting under

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MR 88-0036 revealed a failed amplifier board on the flow trans-

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and the RCIC system was declared operable at 6:00 p.m.

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On January 14, 1988, the HPCI and RCIC systems were declared inoper-able non-simultaneously. At 11:45 a.m. the HPCI system was removed from service to troubleshoot and repair the gland seal vacuum pum Maintenance and operability tests were completed satisfactorily and HPCI was returned to service at 3:17 p.m. The RCIC system was declared inoperable twice for unrelated reasons later. on January 14, 1988. At 4:40 p.m. , RCIC was removed from service when RCIC turbine steam supply valves RCIC-15 and RCIC-16 were isolated in order to facilitate the replacement of the manual isolation valve for pressure switch PS-13-870. The valve would not close fully and was replaced under MR 88-072. Maintenance was completed and RCIC declared operable at 6:20 p.m. The RCIC system was started at 8:55 p.m. to take IST vibration monitoring dat The RCIC pump outboard bearing vibration monitoring point Z-2 reading was in the required action range. As a result, RCIC was declared inoperable at 9:15 On January 15, 1988 additional testing and vibration data analysis indicated satisfactory results and RCIC was declared operable at 8:40 Following the declaration of each system inoperability above, the licensee performed alternate testing as required by TS 3.5 and made the required notifications to the NRC0 The licensee responded promptly to each event above. Good planning and coordination between plant disciplines minimized the time the plant was in a limiting condition for operatio The inspectors had no further question .2 ADS By pass Switch Annunciator Ground During surveillance to locate electrical grounds, the licensee iden-tified a 35V ground between the contacts of the ADS by pass switch 2E-S12 and its associated annunciator. In order to eliminate the '

ground, LL/J 88-001 was issued and executed on January 5, 1988 to lift the leads of the annunciator contact of switch 2E-51 The annunciator alarm function was disabled when the contact leads were lifte The installation of ADS by pass switch 2E-S12 was an Appendix R required modificatio It is a keylock switch with normal and by-pass positions that, when placed in by pass, blocks all remote oper-ation of the safety relief valves to prevent inadvertant opening due to a fire in the control room or cable vault. The key can only be removed with the switch in the normal position, and the switch cannot be placed in by pass with the key removed.

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.10 To ensure that the switch was not inadvertently placed in the by pass position while the annunciator alarm was inoperable the licensee removed the key from the switch and controlled it as such beside the switch. The normal ADS by pass timer reset switches, 2E-S2A and 2E-S28, which alarm on the same annunciator as the 2E-S12 switch are

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unaffected t/ this LL/ The safety functions of the ADS by pass switch are unaffected by this LL/ The inspectors identified no violations or safety concern . Maintenance Activities 9.1 Control Rod Blade Rack Assembly Repositioning

' Licensee non-conformance report (NCR) 87-30, dated November 24, 1987, identified several potential discrepancies in the implementation of engineering design change request (EDCR) 74-26, Revision 1, entitled New Spent Fuel Racks, issued on January 12, 1978. Specifically, NCR 87-30, Section 3.C addressed the verification of the position of the control rod blade (CRB) storage rack assemblies in the spent fuel pool (SFP). Revision 2 to EDCR 87-26, dated May 20, 1980 required a minimum of five inches of clearance between each CRB rack assembly and the SFP wall and other obstructions. Only one CRB rack aksembly remains in the SFP, but due to a lack of quality documentation the CRB rack assembly clearances could not be determine The rack assembly was located at the east wall of the SFP just south of the cask pa The licersee generated MR 87-3241, dated December 30, 1987 to repo-sition the CRB rack assembly such that the minimum clearance require-ments of EDCR 74-26, Revision 2 would be satisfied. The MR included a safety evaluation addressing the seismic design, criticality and load handling requirements of the CRB rack assembly as well as an ,

installation guideline for the CRB rack assembly relocatio The Plant Operations Review Committee (PORC) reviewed and approved MR 87-3241 on December 31, 1987. A pre-work brief was held with par-ticipation by cognizant maintenance, reactor and computer engineer-

ing, radiation protection and operation personnel in attendance. The CRB rack assembly relocation was started on December 31, 1987 in the

mid-afternoo The contents of the assembly which included five

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double-blade guides, two single-blade guides and two control rod blades were removed from the rack and temporarily secured at the SFP south guardrai The CRB rack assembly was then lifted by the reactor building crane, rotated 90 degrees and temporarily set away l

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from the work area. Three positioning blocks, fabricated on site for the rack assembly relocation, were then installed. One twelve inch block ~ was installed along the south face of the cask pad and two six-inch blocks were placed along the SFP east wall. .The CRB rack assembly was lifted and set as close as possible to the positioning blocks and then 'the blocks were removed from the pool .and the two control rod blades -were returned to the CRB rack assembly. On January 4,1988, the double- and single-blade quides were returned to the rack assembl The maintenance effort was monitored by peer QC inspectors and was documented in QC inspection report number M87-111. Five criteria listed below were identified as requisites in report M87-111: The fabricated positioning blocks dimensions were accurate to 0.25 inche . All guideline prerequisites and precautions were complete " A cable clamp was installed on the trolly mounted hoist per guideline step 7.3 to limit maximum lift height to no closer then eight feet below SFP water leve . Position blocks were properly installed CRB rack assembly was as close as possible to the position blocks.

l The inspectors were present at the PORC review of MR 87-3241, the

! prework brief and most of the work ef for The PORC quorum was

! assembled specifically to review MR 87-324 The review was per-

! ceptive and probin The prework brief was very comprehensive l addressing all significant requirement The CRB rack assembly l repositioning was accomplished in an efficient, well-controlled I

manner. The inspectors identified no violations or safety concern .2 Condensate Storage Tank Instrument Line Leak On January 2, 1988, water leakage was identified from a small, through-wall crack in a 1.5-inch instrument flush line off the con-densate storage tank (CST). The leak was isolated by closing valve CST-17. The crack resulted when the process water froze and expanded due to several days of extremely cold atmospheric temperatures. The heat tracing circuit for the line was inoperable with an MR outstand-in On January 4, 1988 the line was discovered to be leaking slightly again. The leakage was stopped by retorquing CST-17. The affected section of pipe was replaced and temporary heat tracing was installed on January 7, 1988 in accordance with MR 88-00 .

The majority of the leakage was contained with the waste surge tank (WST) retaining moat, however, an amount of CST water had leaked out-side the WST retaining moat. In an attempt to conservatively quan-tify the leakage, the licensee chipped away and collected all the ice in the area of the CST, including a significant quantity of ice that was most probably present from previous snowfalls. Approximately 200 gallons of water were collecte Radiation protection personnel surveyed the CST area. Their results indicated less than 1K dpm/100 cm 2

. Tritium activity was 1.1 x 10 E (-5) uCi/m Review of this event revealed that heat tracing circuit 22 for the affected line had been inoperable since 1984. Because no indications of process freezing were observed prior to this event the MR to repair heat tracing circuit 22 was given a very low priority status.

l On January 22, 1988, a second pin hole leak was discovered on the l

same line. The licensee believed that it occurred during the same freeze as the previous crack but went_ undetecte Review of these events revealed that the cracked line was a field installation during construction to facilitate flushing 6f the l fnstrument piping of construction generated debris, Following an l operational analysis the licensee determined the function of the flush line was nn longer required. On January 22, 1988, MR88-059 was implemented and the flush line was terminated and capped to prevent future freeze events. Inspector findings regarding this matter are described in Section .3 Reactor Building HVAC Isolations Beginning on January 10, 1988, during the current inspection period i there have been numerous occurrences of reactor building heating, j ventilation and air conditioning (HVAC) isolations due to the freez-

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ing of instrument air lines to the reactor building ventilation dampers allowing them to drift close The first freeze up on January 10, 1988 was attributed to the fact that the instrument air dryer had been bypassed for a prolonged period allowing excessive moisture to enter the system. As corrective actions the instrument

! air system was vented and guidance was provided to reduce the unavailability of the dryer. Subsequent to the venting, several more reactor building ventilation isolations occurred due to instrument air line freezups. The maintenance department installed heat tracing and insulation on the affected lines in an attempt to preclude fur-ther freezeups, but several more have occurred since. At least one reactor building ventilation isolation occurred on each of the fol-lowing dates: January 10, 11, 15, 27, 28, 29, 30 and February 3, 4, 5, 6, The licensee is currently attempting to scope and correct the instrument air line freezeups. Inspector findings regarding this matter are described in Section .

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9.4 Preparations for Cold Weather Operations On September 27, 1979, the NRC issued bulletin IEB 79-24: Frozen Lines, describing the ECCS recirculation line freeze event at Davis-Besse, Unit 1. Several other facilities were identified as having experienced similar freeze event The bulletin requested that licensees take action to review their plants to ensure that adequate measures were taken to pro'.ect safety related processes, instrument and sample lines from freeze events. The licensee response, WVY 79-128 dated October 30, 1979, indicated that during initial plant operations freezing had been a problem with several systems including reactor building ventilation valves. The licensee stated further that the problems had been fully resolved based on satisfactory operations during record cold condition The inspectors reviewed the licensee process for preparations for cold weather operations and freeze protection. The licensee did not utilize a specific approved procedure to ensure plant protection from the effects of subfreezing condition Rather, the process was con- .

trolled informally by the operations department and system re-align- i ments were documented via administrative configuration control pro-cedures. An example was the issuance of LL/J 88-002 to control the circulation water bay south louvers closed for winter operation Heat tracing circuitry energization only was verified by status light indication during assistant operator (AO) plant rounds. There was no heat tracing surveillance procedure to verify thermostat settings and actual circuitry conditio The recent CST flush line freeze cracks and the licensee inability to correct the reactor building ventilation isolations caused by instrument air line freezeups, indicate that the licensee needs to readdress the requested actions of the IEB 79-24 and to implement an approved procedure to control preparation for cold weather opera-tion This item is unresolved pending subsequent NRC resident inspector review of the licensee corrective actions to preclude recurrence of similar events (50-271/87-23-02).

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10. Review of Licensee Response to NRC Initiatives

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10.1 NRC Compliance Bulletin 87-02: "Fa stener testing to determine conformance with applicable material specifications", dated

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November 6, 1987. The bulletin requested that licensees 1) review their receipt inspection requirements and internal controls for

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fasteners and 2) independently determine, through testing, whether j fasteners in stores at their facilities meet required mechanical and chemical specification requirements.

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The licensee responded to NRC Bulletin 87-02 by letter FVY 88-03, I dated January 12, 1988, which was submitted in accordance with the response time required by the bulleti The licensee addressed each requested action of the bulleti The resident inspectors accom-panied licensee personnel and participated in the selection of a representative 'and proportional sample of eleven safety-related fasteners, ten safety-related nuts, ten non-safety-related fasteners and ten non-safety-related nuts from existing, in use, stores. The selected fasteners were tested for chemical analysis, Rockwell hard-ness, and mechanical properties. Testing was performed by a VYNPC approved vendo The chemical analysis testing results indicated that two of the sample safety-related nuts had single elements below the specified composition range, as identified below:

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NUT VY-87-02-13SR-N carbon content 0.05% below specified rang NUT VY-87-02-18SR-N chrome content 0.44% below specified rang As a result of these discrepancies,' the licensee retested all the remaining nuts from the respective purchase order lot Two nuts remained from the same lot as sample VY-87-02-133SR- testing *

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indicated results were within specifie'd chemistry and hardness ranges .

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for bot Five nuts remained from the same lot as sample l VY-87-02-18SR- Testing indicated results were identical to the l sample test, in that chrome content was typically 0.44% below spec- !

l ified range. Evaluation of the chemical composition, hardness test-ing and proof testing of these samples concluded that the structural functionality of the samples was not impaired and, therefore, use of them would not have affected the operability of safety-related component Based on the satisfactory results of the bulletin-required testing, the licensee plans no further action at this tim As required by NRC Inspection Manual Temporary Instruction TI 2500/26, the inspectors observed the tagging of the selected specimen and the recording of specimen marking or specifications on the field data sheet. The licensee subsequently codified the specimen by initial-isms and serial numerals as follows:

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ID# VY-87-02-XX SR-F(or N)

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ID# VY-87-02-XX NNS-F (or N)

where-VY-87-02 = Vermont-Yankee NRC Bulletin 87-02 XX = specimen number. (1-48)

SR = Safety Related NNS = Non-nuclear Safety F = Fastener N Nut The inspectors reviewed the transcriptions of the data from the specimen tags and field data sheets to the licensee purchase order to the vendor response. No discrepancies were identifie One dimensional discrepancy was _ identified by the licensee during the review of the initial test results of specimen nut VY-87-02-13SR- This specimen .was described initially as a 3/4 X 10 nut but was actually a 5/8 X 11 nut. The discrepancy was perpetuated from tag-ging through the first vendor repor The licensee identified the error during review of the test results and implemented the forrec-l tion. Dimension verification was not an issue or requirement of NRC

Compliance Bulletin 87-02 and had no impact on the test results for this specimen.

l The licensee responded promptly to the direction of NRC Compliance

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Bulletin 87-02 and conservatively tested the remaining lots of the

, two specimens with _ out-of-speci fication chemistry analysi The inspectors identified no violations or safety concerns and had no further questions.

l 10.2 08 Breaker Mechanical Trip Mechanisms l

The licensee reviewed the Westinghouse DB breaker and Amptector over-current trip device clearance discrepancy found at the R. E. Ginna

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station (Refer to Attachment A) for applicability at VYNP The review indicated that only four DB breakers are in service onsit They are located in the cable vault room and serve as the main and tie breakers for the A and B main station batteries. These breakers L are manufactured by Westinghouse but the trip mechanisms are electro-i magnetic trip devices not the Amptector trip devices assocated with the Ginna breaker discrepancy. All other switchgear breakers onsite are manufactured by G.E. No Amptector trip devices are installed on any breaker onsite. The inspectors had no further question .

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1 Periodic and Special Reports Upon receipt, .the inspector reviewed periodic and special reports submit-ted pursuant to Technical Specifications. This review verified, as appli-cable: (1) that the reported information was valid and included the NRC-required data; (2) that test results and supporting information were consistent with design predictions and performance specifications; and (3) that planned corrective actions were adequate for resolution of the problem. The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The following reports were reviewed:

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Monthly Statistical Report for plant operations for the months of December, 1987 and January, 198 The inspector noted no deficiencie . Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss the findings. A summary of findings for tionthe report and priorperiod was issuanc to report also discussed at the conclusion No proprietary of thew information J,nspec-iden-tified as being included in the report. Attachment A was provided to the licensee to assist in the determination of applicability to VYNP On January 25 and 26, 1988, the NRC Region I Reactor Projects Section Chief for Vermont Yankee Nuclear Power Station (VYNPS) met separately with Mr. D. Bauer, Assistant to the VYNPC Vice President and Manager of Opera-tions, and with Mr. J. Thayer, the Yankee Atomic Electric Company Project Manager for VYNPS. The meetings included: (1) general discussions of acceptable methods for implementing thr: NRC rules for correspondence handling, pursuant to 10 CFR 50.4 effective January 5,1987, (2) current points of contact with the NRC Region I staff for administrative, schedular and technical matters including event communications with the Commonwealth of Massachusetts, and (3) current licensee practices both for internal tracking and for informing the NRC staff of the status and schedule for licensing actions, including proposed technical specification changes and Safety Issues Management System (SIMS) items.

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i ATTACHMENT A Event at an Operating Power Reactor On December 21, 1987, the "B" RHR pump failed to start during surveillanc Licensee checks and consultation with the vendor identified the problem as being due to lack of clearance between the Amptector (solid state overcurrent trip installed as a breaker modification) actuator arm and the breaker trip ba All 12 Class 1E DB breakers were then checked, with the "B" SI pump failing to start. The problem was an intermittent one: additional checks of the RHR pump breaker did not produce a failure to close until the 14th try and the SI pump breaker did not fail to close until the 7th actuation. These were the first failures experienced and at least monthly equipment starts have been performed since the Amptector modification was installed about May of 198 By December 23, all Class 1E DB breakers with the Amptector modification had been verified to be properly operable, with adjustments made as necessary (by bending the actuator arm) to assure that the recommended 1/32" clearance exists between the Amptector actuator arm and the trip bar. Each breaker was declared .I inoperable during testing and adjustment: no action statements were exceede About 32 more DB breakers are installed at Ginna in non-1E applications; these are to be adjusted as necessary during their next scheduled surveillance. The licensee has also noted that the breaker operating voltage on the breakers which failed war. 140 VDC due to a battery equalizing charge being in progres The other breaker checks appear to have been performed at the normal 130 VDC level. The licensee considers this to be a potential contributing factor which does not change the validity of the 1/32" clearance.