IR 05000271/1985030

Insp Rept 50-271/85-30 on 850921-1018.No Violation Noted. Major Areas Inspected:Actions on Previous Insp Findings, Plant Shutdown Operations,Plant Physical Security,Followup of Events & Refueling Activities

ML20136D714
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	11/14/1985
From:	Raymond W, Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20136D680	List: IR 05000271/1985030 ML20136D676
References
50-271-85-30, NUDOCS 8511210353
Download: ML20136D714 (21)

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U. S. NUCLEAR REGULATORY COMMISSION  !

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REGION I L

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Report No. 85-30 l Docket N License No. DPR-28 Licensee: Vermont Yankee Nuclear Power Corporation RD 5, Box 169, Ferry Road Brattleboro, Vermont 05301  :

Facility Name: Vermont Yankee Nuclear Power Station Inspection At: Vernon, Vermont Inspection Conducted: September 21 - October 18, 1985 t

Inspectors: William J. Raymond, Senior Resident Inspector  ;

Thom B. Silko Resident Inspector Reviewed b: .N 11'11am J. R ynMd, Senior Resident Inspector

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Approved by: Y - -

L. 'E. Tripp,:hief, Reactor Projects J/[/N8I 7 /

Section 3A, Projects Branch J j Inspection Summary: Inspection on September 21 - October 18, 1985 (ReportNo. 50-271/85-30)

Areas Inspected: Routine, unannounced inspection on day time and backshifts i by the resident inspectors of: actions on previous inspection findings; plant !

shutdown operations, including operating activities and records; plant physical i security; implementation of the interim Peer Inspection Program; followup of

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events; refueling activities; followup of technical specification related issues; and, review of the recirculation pipe replacement program and proce-l dures. The inspection involved 139 hours0.00161 days <br />0.0386 hours <br />2.29828e-4 weeks <br />5.28895e-5 months <br />, i

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Results: No violations were identified in 8 areas inspected. Operational status reviews identified no conditions adverse to safe operation of the fa-l cility. The cause of damage to the pressure tube of IRM 'B' warrants further ,

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evaluation by the licensee and review by the NRC staff (section 8.6), i t

8511210353 851114  !

PDR ADOCM 05000271 0 PDN

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DETAILS

1. Persons Contacted '

l Interviews and discussions were conducted with members of the licensee staff and management during the report period to obtain information per-tinent to the areas inspecte Inspection findings were discussed l periodically with the management and supervisory personnel listed belo ,

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Vermont Yankee i Mr. _ J. Babbitt, Security Supervisor Mr. P. Donnelly, Maintenance Superintendent Mr. J. Pelletier, Plant Manager  :

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Mr. D. Reid, Operations Superintendent  !

Mr. R. Wanczyk, Technical Services Superintendent Yankee Atomic Electric Company l Mr. J. Cox, Engineer '

A meeting was held with the Vermont State Nuclear Engineer on October 18, 1985 in the NRC Resident Office to discuss NRC inspection of outage acti-l vities and recent events. The physical security event of September 20, 1985, the inadvertant exposure in the TIP room on August 9,1985, and the

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identification of radioactive material in the North owner controlled area

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i i l Status of Previous Inspection Findinas l l

, 2.1 (Closed) Follow Item 85-25-05: Identification of Ground on DC-10, i

Circuit 4. The licensee reviewed the 'A' MSIV control circuitry and i i identified a loose wire on the DC solenoid for the valve. The field l 1ead to the solenoid had broken at the lug on the MSIV terminal block i and had caused the ground on the 'A' station battery when the lead came in contact with the housing. The licensee concluded that the t lead weakened over time due to repeated lifting of the wires for an- l nual preventive maintenance on the valves. The MSIV actuators in-

! clusive of the solenoids were removed for the pipe replacement out-age. The Itcensee plans to review the terminal blocks and wiring on the other valves during the refueling outage. The item is close t

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2.2 (0 pen) Unresolved ! tem 85-25-06: Cause of Ground on 'A' Recircula-L tion Pump Suction Valve, V2-43A. The licensee completed a prelimi-t nary investigation of the suction valve circuitry following plant ,

l shutdown and identified a short between the suction and discharge i.

L valve position indication cablos as they pass through the drywell l'

electrical penetration. Cables located on the bottom of penetration X105C were in contact with the steel sleeve which could result in l

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electrical shorts from conductor to conductor, or from conductor to ground. Drywell penetration X105C is a General Electric penetration assembly, catalog No. 237X680G016. There is no protective insulator suppited with the assembly to prevent interaction between the cables

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anc the metal edge of the assembl ~he licensee inspected the drywell side of six other electrical pere-trstion types and noted that conductors were in contact with the shirp edge of the assembly in each penetration inspected. Four of the six penetration types inspected (control and indication, CRD posi-tion indication, 480 volt power, and neutron monitoring) were instal-led such that insulation damage could occur. The thermocouple pene-trations are expected to have a similar installation configuration as X105C, and will be examined further. The SKV power penetrations are not expected to have the same problem due to the size and stiffness of the cable The licensee evaluated these findings under a potential report form dated October 10, 1985 and determined that the item should be reported to the NRC as a licensee event report (LER) under 10 CFR 50.73(a)(2)

(v). Further licensee review of the scope of the problem and the corrective action plan was still in progress at the conclusion of the inspection. This item remains open pending submittal of a LER and subsequent NRC review of the licensee's corrective action .3 (Closed) Follow Item 83-02-03: Olversity of Scram Instrument Volume Level Instruments. By letter dated September 10, 1985, the NRC staff issued a safety evaluation report for the design of the VY scram in-strument volume system. The NRC staff found that the current scram system design is acceptable without diversity in the level measure-ment system. This item is close .4 (Closed) Violation 84-21-07: Bolting of Shroud Head to Reactor. The Itcensee issued OP 1201, Revision 10 dated September 20, 1985, and OP 1200, Revision 10 dated August 12, 1985, to provide improved instruc-tions to plant workers for assembly and disassembly of the reactor and drywell system The inspector reviewed both procedures and noted that revised instructions for fastening the shroud head - moisture separator were incorporated, along with other revisions to assure the correct performance of maintenance activities. This item is close .5 (0 pen) Unresolved Item 85-28-08: Diesel Generator Fuel Oil Check Valve Replacemen The inspector reviewed test results for the rou-tine monthly surveillance of the ' A' and 'B' diesel generators con- i ducted per VYOPF 4126.03 on October 9, 198 The inspector noted that the diesels started in less than 13 seconds as required by the technical specifications, without first manually priming the fuel oil

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! heade The test results confirmed the licensee's previous conclu-l sion that the diesels would be operable with 0 psig indicated on the

! fuel oil header pressure and at least 85 inches of level in the day tan The licensee's review of the original and modified fuel oil check valve designs was still in progress at the conclusion of the inspec-tion. This item remains open pending completion of the licensee's corrective actions and subsequent review by the NR .6 (0 pen) Follow Item 84-21-02: Control Rod 18-11 Malfunction. Follow-ing shutdown for the outage, the licensee exercised control rod 18-11 on October 7, 1985 and found that the rod moved to position 48 without problem. The licensee examined the rod as the cell was disassembled

! during refueling operations. The licensee uncoupled the rod from its drive from above and noted no unusual conditions in the rod, spud, drive, uncoupling pin or guide tube. No damage was identified that would have caused the rod to not move beyond position 46 during the previous operating cycl Licensee investigation of the problem with rod 18-11 was still in progress at the conclusion of the inspection. This item remains open pending completion of the licensee's investigation and subsequent review by the NRC.

l 2.7 (0 pen) Follow Item 84-08-03: Station Batteries. The licensee sub-mitted a Part 21 report to the NRC by letter dated June 29, 1984 to describe a potentially generic problem with Exide Type EC11 cells used in the uninterruptible power supply (UPS) system. The licensee replaced both sets of UPS batteries in July,198 The Part 21 report for the Exide Series 'E' cells described a cor- '

rosion problem that results in cracked boss seals and nodular cor-rosion of the lead posts. The corrosion causes the copper inserts -

inside the battery posts to be exposed to acid, which results in copper contamination of the negative plates. The licensee reported that the corrosion problem could degrade the current carrying capa-bility of the battery and cause the cells to approach an accelerated '

end-of-life condition. The onset and development of this failure mechanism can be detected and trended through the existing battery surveillance progra During this inspection, the inspector observed a battery post that was removed from the UpS batteries replaced in 1984 and noted an ex-tensive amount of corrosion and material wastage of the lead coating at the point corresponding to the normal level of the electrolyt l The lead coating was eroded away to the point that the copper insert was clearly exposed and a significant potential for loss of mechanical integrity of the post existed. Mechanical failure of the post could result in dropping the plates within the cell, an !

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L open circuit condition on the cell, and a loss of electrical contin-utty in the battery bank. A post that is severely eroded could pass routine surveillance tests, but then be subject to abrupt failure from vibratory or seismic loads. This type of failure mechanism was not identified by the licensee in the Part 21 repor The above concerns were discussed during a meeting with licensee per-sonnel on October 11, 1985. The licensee was requested to evaluate whether the Exide Part 21 report should be revised to identify the potential failure mechanism under seismic loading. During discussions with YAEC engineering, the inspector noted that a significant amount of material wastage had been observed on a post removed from Cell #11 of the 'A' station battery when it was disassembled for examinatio The inspector also asked the licensee to address the similarities, if any, between the Exide problem and the corrosion previously observed on the 125 VDC station batteries, which are C&D Type LC-33 cell The licensee stated that YAEC and C&O engineering had addressed this issue and concluded that the C&D cells would not be subject to struc-tural failure. The licensee stated that a summary of the engineering evaluations would be provided for NRC review. Both station battery banks are scheduled for replacement during the 1985 refueling outag This item remains open pending completion of the licensee actions described above and subsequent review by the NRC, 2.8 (0 pen) Follow Item 85-25-07: Diesel Generator Brush Rigging. The inspector met with Itcensee personnel on October 11, 1985 to discuss ,

the brush rigging on the Colt-Beloit diesel generators. The inspec- ;

tor described the details of tha brush rigging on a diesel that failed at another facilit The inspector recommended that the licensee inspect the brush rigging during the preventive maintenance checks scheduled for the present outage. The licensee stated that the item would be considered for incorporation in the inspection schedul This item remains open pending completion of the licensee's actions and subsequent review by the NR .9 (0 pen) Follow Item 85-25-03: North 40 Contamination. The licensee reported that he had completed a survey of the yard-trash plie located in the North section of the owner controlled area. No additional radioactive material had been identified based on a survey asing a PRM-6 survey instrument with a Na! detector held about 3 feet uff the groun The licensee reported further that a survey of the entire owner controlled area had been completed and no radioactive material had been identifie The inspector completed a confirmatory survey of the trash pile on October 17, 1985 with the following licensee survey instruments:

RM-14 VY #1009; and, PRM-6, VY #L-499. The survey was completed using the PRM-6 instrument scanning at ground level. Any indications

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greater than 10,000 counts per minute (CPM) above background on the PRM-6 were investigated further with the RM-14 and indications greater than 100 cpm above background on that instrument were considered to warrant removal in accordance with the present plant release limit Two areas of activity were located on or near the trash pile. A piece of material was retrieved from the trash pile which caused readings of 1100 corrected cpm general and which read 3200 cpm on contact with the RM-14. The inspector also identified activity in a mound of what appeared to be black decontamination grit which read 10,000 counts above background on the PRM-6, but showed no increased readings on the RM-14. The cobalt material was turned over to licensee personnel for evaluation and followup on October 17, 1985. Plant Health Physics personnel took actions to re survey the area and remove material as require The status of licensee actions were reviewed on October 18, 1985. A second piece of material was removed from the trash pile and the mound of ' black beauty' was removed until activity was less than 10,000 cpm above background on the PRM- Licensee analysis of the materials retrieved from the pile identified the following: metal chip - 0.21 micro-Ci (uC1) of Co-60; piece of rubber - 0.6 uCi Co-60 and 0.012 uti Sb-125; and, grit sample - 0.002 uCi Co-60, 0.002 uC1 81-214 and 0.002 uti Cs-137. These isotopes are fission and activa-tion products that originated in the plan The quantities of the materials present did not create a health hazard. No NRC regulatory limits were exceeded by the presence of the material in the fiel The licensee concluded that it is possible to find more material in the pile if a sufficiently detained survey is complete However, the licensee concluded that the surveys completed with the PRM-6 scanning at 3 feet above the ground would assure detection of any material with gamma activity greater than 3 uCi located on the groun This amount of activity would cause a 10,000 cpm increase in the PRM-6 readings. Definition GG in the facility technical specifications classifies any material with greater than 5 uCi total activity as radioactive. Based on the above, the licensee does not plan to in-vestigate the owner controlled area any further for the presence of radioactive material at this tim The inspector requested the licensee to provide further information to support his correlation between activity and the expected PRM response, and to consider performing a demonstration of the ability of the survey technique to detect 3 uC This item remains open pending further review by the NRC staff of the licensee's correlation regarding the PRM-6 sensitivit .

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l 2.10 (Closed) Follow Item 84-10-04: Recirculation System Decontamination.

l Following further evaluation of the Can-Decon test results, the li-censee concluded that material exposed to the process would not become more susceptible to intergrannular stress corrosion cracking. How-ever, no chemical decontamination of the recirculation system was completed in 1984, and a process using Citrox was selected for use during the 1985 decontamination of the recirculation system. The inspector had no further questions regarding the licensee's use of the Can-Decon proces The inspector reviewed the licensee's safety evaluation, documented in memoranda form G. D. Weyman dated June 25, 1985, September 20, 1985 and October 9, 1985, for the use of the Cirtox process by Pacific Nuclear Systems, Inc., during the 1985 outage. The licensee's con-trols for use of the process included: material testing following exposure to the decon solution for a specified duration, which showed no adverse general corrosion effects; limited exposure of the recir-

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culation system components to the decon solution - 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> for the Citrox and 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for permanganate; control of the decon process per procedure DP 2167-003; chemistry sampling during the decon process to monitor performance and impact on the recirculation system; subsequent inspection of recirculation components that will be reused - the com-ponents will be examined for delta ferrite content and a corrosion resistant cladding will be applied as applicable; and, the use of plugs and level control in the recirculation piping to keep the solution out of the reactor vesse The licensee's evaluation noted that some test data exists which suggest that the process chemicals could cause an increase in sensi- .

tivity to intergrannular attack for some of the exposed material, but no adverse safety concerns would result from use of the process. No inadequacies were identified regarding the licensee's safety evalua-tion or the use of the Citrox process for the 1985 recirculation decontaminatio This item is close .11 (Closed) Unresolved Item 85-14-02: Drywell inspection. The licensee completed an inspection of the general conditions in the drywell fol-lowing the shutdown on September 21, 1985 and determined that no damage had occurred as a result of the inadvertent containment spray actuation on April 2, 1985. The inspector completed an inspection of the general conditions in the drywell on October 1,1985 and no in-adequacies were identified. This item is close .12 (0 pen) Follow Item 85-20-03: Licensee investigation on September 21, 1985 of the ground on the negative leg of the 'B' station battery identified a fault in the trip circuit for the 'B' recirculation motor generator (MG) set. The fault was found by isolating the B MG 4 set control circuitry from the 'B' station batter However, during subsequent actions to troubleshoot the problem, the fault in the control circuit cleared for reasons unknown to repair personne _

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Licensee actions to investigate the problem continued. This item will be reviewed further on subsequent inspections to follow the status of the 'B' battery and to review licensee corrective actions to clear the ground conditio .0 Observations of Physical Security Selected aspects of plant physical security were reviewed during regular and backshift hours to verify that controls were in accordance with the security plan and approved procedures. This review included the following security measures: guard staffing; random observations of the secondary alarm station; verification of physical barrier integrity in the protected and vital areas; verification that isolation zones were maintained; and implementation of access controls, including identification, authoriza-tion, badging, escorting, personnel and vehicle searches. No inadequacies were identified, except as noted belo A contractor arrived at Gatehouse 2 to gain access to the protected area at 3:15 P.M. on September 20, 1985 and was directed by the guard to con-tractor gatehouse 3 for processing. While enroute to gatehouse 3, the individual mistakenly entered a warehouse access gate which was open for a deliver The unauthroized, uncontrolled entry was not detected by the guard posted at the gate. The contractor proceeded to his onsite contact, who realized he had gained unapproved access, and escorted him at 3:30 to gatehouse 3 for proper processing. The security shif t supervisor and security management were notified and response actions were initiate The guard at the warehouse gate was relieved from duty and held for ques-tioning. Licensee investigation of the incident accounted for the con-tractors activities while unescorted in the protected area and determined that no safeguard threat had occurred. The licenseo made a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> noti-fication to the HQ Outy Officer at 8:11 A.M. on September 21, 1985 and briefed the resident inspector of the incident at 10:00 A.M. on September 21, 198 The resident inspector reviewed the licensee's interim corrective actions to prevent recurrence. Corrective actions to better control delivery ac-tivities were reviewed further with the Security Supervisor on September 23, l 1985. The completion of actions to improve monitoring of the protective area barrier were verified as complete by the inspector on September 30,

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1985, along with interim compensatory measuras that were taken prior to that date. No inadequacies were identifie The failure to control access to the protected area on September 20, 1985, l was a violation of NRC requirements. Further NRC review of the event and followup to the violation is described in Inspection Report 85-31 dated October 11, 198 ____ _ _ _ -_- - ---_-_

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l 4.0 Shift Logs and Operating Records

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Shift logs and operating records were reviewed to determine the status of the plant and changes in operational conditions since the last log review, and to verify that: (1) selected Technical Specification limits were met; (2) log entries involving abnormal conditions provided sufficient detail to communicate equipment status, correction, and restoration; (3) opera-ting logs and surveillance sheets were properly completed and log book reviews were conducted by the staff; (4) potential reportable occurrences were filed as licensee event reports when required; and, (5) Operating and Special Orders did not conflict with Technical Specification requirement No unacceptable conditions were identifie . Inspection Tours and Status Reviews Operational status reviews were performed to verify conformance with the technical specifications. The operational status of emergency and power generation systems was confirmed by direct review of control room panel Control room staffing and protocol were reviewed to assure manning require-ments were met and acceptable working conditions were maintained. Li-consed personnel were interviewed regarding existing plant condition Acknowledged alarms were reviewed with licensed personnel as to cause and corrective actions being take Plant tours were conducted to observe activities in progress and verify compliance with administrative requirements. Systems and equipment in areas toured were observed to confirm operational status and to monitor for fluid leaks and abnormal vibrations. Pipe snubbers and restraints were observed for proper conditions. Plant housekeeping conditions were observed for conformance with AP 0042, Plant Fire Prevention, and AP 6024 Plant Housekeepin The plant was shutdown on September 20, 1985 to begin a 32 week outage to replace the primary loop recirculation piping and to complete routine re-fueling and maintenance activities. Major plant activities reviewed and findings during this inspection period were as described belo .1 Operational and survoillance activities in progress were reviewed for compitance with the following plant procedures: OP 2115 for primary containment de enerting on September 20,1985; plant shutdown and cold shutdown operations per OP 0111 and 0112; residual heat removal system operation per OP 2124; control rod friction testing per OP 4111; and drywell and reactor systems disassembly por OP 120 No inadequacies were identifie .2 The actions taken by plant personnel during periods when equipment was inoperable were reviewed to verify technical specification limits wore met; alternate surveillance testing was completed satisfactorily; and, equipment return to service upon completion of repairs was prope _ _ _- _-_ _ ____ .-

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r The above reviews were completed for the following items: loss of the rod worth minimizer function during shutdown activities on

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September 20, 1985 and use of the rod selection template and a second l reactor operator per Technical Specifications 3.3.B.3; loss of power j to the 'B' loop recirculation discharge bypass valve (V2~548) on

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September 21, 1985 and actions to assure LPCI operability per Techni-cal Specification 3.5; loss of intermediate range monitor channel 'B'

from September 27 - October 1, 1985; loss of one of two reactor build-ing ventilation monitors on September 30, 1985; and, loss of the diesel fire pump for two hours on September 30, 1985. No inadequacies

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Power to the 'B' recirculation loop discharge valve was lost on

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l September 21, 1985, when the fuse blew for the valve control cir-cuitr Preliminary reviews by the licensee determined that the fuse blew as a result of a short circuit caused by chaffing of the wire

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! licensee's final evaluation and repair actions for valve 54B will be l followed on a subsequent inspection (IFI 85-30-01).

5.3 The feedwater sparger leakage detection system was not required to be operable during the inspection period due to the shutdown condi-

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tion of the plan The monthly performance summary provided by the licensee in accordance with letter FVY 82-105 will not be provided until the plant returns to steady state power operations in the l Spring of 198 The inspector noted that the licensee completed an ultrasonic (UT)

inspection of the feedwater nozzles in accordance with his commitment to the NRC. The preliminary UT inspection results reported by the licensee on September 25, 1985 indicated there were no relevant indi-cations identified by the examinations. Liquid penetrant examination of the nozzle inner radius will be completed prior to plant startup.

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No unacceptable conditions were identifie .4 The status of the Residual Heat Removal, Residual Heat Removal Service Water, Service Water, Core Spray, and Standby Liquid Control systems was reviewed to verify that the systems were properly aligned to sup-port cold shutdown and refueling operations. The review included a verification that (1) major flow path valves were correctly position-ed; (2) power supplies and electrical breakers were properly aligned; and, (3) the general condition of major components was acceptable, including lubrication, cooling water supply, and leak tightness. No

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inadequacies were identifie .5 The inspector reviewed implementation of jumper and lifted lead (J/LL) request 85-52 to verify that controls established by AP 0020 were met; no conflict with the technical specifications were created; and, the request was properly approved prior to installation. No inadequacies were identified.

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5.6 Actions completed under Switching Order 85-675 were reviewed on i

October 10, 1985 to verify equipment was controlled in accordance <

with AP 0140, VY Local Control Switching Rules. No inadequacies were identifie Other reviews associated with this tagging order are discussed in paragraph 7.1 below, l 5.7 Radiation controls established by the licensee, including radiologi-l cal surveys, condition of access control barriers, and postings within l the radiation controlled area were observed for conformance with the i requirements of 10 CFR 20 and AP 0503. Work activities were reviewed I for conformance with RWP requirements. The item described below l warranted inspector followup.

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5. Water spray from open vent valves (#107) on the hydraulic con-trol units (HCU) resulted in the spill of reactor water onto the l HCU bases and the surrounding floor at 12:45 P.M on October 7, ,

l 1985. The HCUs and the floor became contaminated with levels up to 100 mrad /hr of beta activity, and up to 40 mrem /hr gamma

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activity. Health physics personnel established posting and con-

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tamination controls for the area by 2:00 P.M. The material did not become airborne. There were no incidents of personnel con-tamination as a result of the spil ,

The licensee established cleanup activities under RWP 1901 and remcved contamination from the floors and the HCU bases. All areas on the base of the HCUs were decontaminated except for the trough area which provides an attachment point for the ski The trough area was painted over to fix the contamination in place and to prevent its sprea The inspector monitored cleanup activities in progress, observed HP controls and decontamination efforts, and interviewed HP per-sonnel involved in the incident. The control of the HCU vent valves is discussed further in section 7.1 below. No inade- '

quacies were identified regarding health physics control .8 While workers were cutting a restraint near nozzle N2E in the drywell at about 11:45 A.M. on October 2,1985, heat from the cutting torch burned through a protective 'Silktemp' cover and melted a portion of ,

a lead blanket. Slag from the lead blanket dropped to the drywell  ;

252 foot elevation and ignited a ploco of form rubber insulation j wrapped around a 1 inch diamoter pipe. The fire watch stationed at the 252 foot elevation immediately extinguished the smoldering foam insulation. No fire emergency was declare ;

Licensee review of the event noted that (1) the first firo exting-uisher selected by the fire watch to extinguish the insulation mal- i functioned, but another unit was immediately available; and, (11) the i fire watch did not notify control room personnel of the fire or use l of the extinguishers, as require Corrective actions were taken i

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to replace the fire extinguisher. The licensee reviewed the role of the fire watch and determined that plant procedures should be modt-fled to delete the requirements to declare a fire emergency when a fire is immediately extinguished by the fire watc In such cases, the fire watch is now required to notify the control room and the

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fire brigade leader will respond to the area to review the inciden The inspector had no further comment on this area at the present

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time. Implementation of fire prevention controls will be examined i further on subsequent routine inspections. This item is open pending further inspection review of the implementation of fire protection program requirements (IFI 85-30-02).

5.9 A medical emergency was declared at about 2:00 P.M. on October 12, 1985, when an I&C Technician became ill af ter being exposed to oil fumes in the turbine building. The individual did not readily re-cover from the fumes after getting fresh air and appeared to have an allergic reaction to the exposure. He was transported by ambulance to a local hospital where he was held for three hours for observation and then released at about 5:00 P.M. on October 12, 1985. There was no contamination involved in the inciden The oil fumes were caused by a malfunction in a dry cleaning machine used to decomtaminate site anit-C clothing. The malfunction occurred when the wrong type of cooling oil was added to the unit, which broke down at the operating temperature of the cleanor. The licensee in-vestigated the incident and took actions to prevent recurrence prior to subsequent use of the dry cleaner. No inadequacies were identifie .10 A PCIS Group III isolation occurred at 11:55 P.M. on October 8,1985 due to a spurious high radiation signal from the West refuel floor radiation monitor. The isolation signal caused the closure of cer-tain containment system valves and the automatic start of the standby gas treatment system. All systems worked properly. The PCIS trip setpoint from the refuel floor monitors is set at about 80 mrem /hr and the refuel floor general area dose rates are normally much less than 5 mrem /hr. The shift supervisor contacted the health physics technician stationed on the refuel floor, who verified that there were no anomalous radiological conditions in the area. Primary and secondary containment integrity was not required at the time since all fuel had previously been removed from the reactor and no fuel or fuel cask movements in the spent fuel pool were in progres The Group !!! isolation was reset and the duty shif t supervisor sub- .

mitted a potential reportable occurrence report for evaluation of the event. No ENS call was made. The oncoming day shift supervisor re-viewed the activities of the previous shift and determined that a report should be made to the NRC por 10 CFR 50.72(b)(2)(ii). The day shift supervisor made an ENS call to the llQ: Duty Of ficer at 8:30 _ - _ _ _ _ _ _ - - _ _ _ - - _ _ _ _ - _ - - - _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ - _ _ - - _ _ _ - _ _ _ _ _ _ _ _ _

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on October 9, 1985. A potential reportable occurrence report was submitted for the late 50.72 notification, which should have been made within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of the event. The night shift supervisor was counseled on the missed notification. The licensee informed the inspector on October 14, 1985 that this item would be reported under 10 CFR 50.73(a)(2)(iv). This action will be followed on a subsequent inspection (IFI 85-30-03).

The inspector interviewed the shift supervisor regarding the failure to make the ENS notification. The shift supervisor stated that he had considered the notification requirement and had concluded it to be not applicable in view of the status of the plant. However, the licensee had not formally released secondary containment integrity requirements at the tim The failure to make the required notification is considered to be a licensee identified violation that will not be cited since it meets the criteria of 10 CFR 2, Appendix C. The inspector had no further comments regarding the Group III isolation. The licensee's position regarding 50.72 notifications is discussed further in section 9 belo .0 Implementation of the Interim Peer Inspection Program

Special QC groups have been set up for the maintenance and I&C Departments for outage related work. QC peor inspection of work by other plant depart-monts is provided from within the departments. The inspector interviewod the Maintenance Supervisor on September 23, 1985 to review the measures estab11:ned to provide for interim implementation of the Peer Inspection program for outage activitie The QC group for Maintenance was established by hiring qualified con-tractor personnel with background in the related disciplines. The group was providing 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> coverage for refueling floor activities under OP 1200, Reactor and Drywell Systems Disassembl The procedure had been reviewed by the QC group as a proroquisite to its performance to assure that the steps listed complied with the requirements of the appitcable vendor technical manual The QC group was also covering other outage maintenance work on a sampling basi The inspector reviewed QC Inspection Report M001 which was estabitshed and in use for the OP 1200 activities. The inspector noted that it contained detailed inspection and acceptance critoria that were appropriate for as-suring the correct performance of activities under OP 1200. The inspector i

interviewed the QC inspector assigned to the refuel floor on September 23, i 1985 and noted he was knowledgeable of the work in progress and the in-spection requirement Implementation of the interim QC inspection program will be reviewed further on subsequent routino inspection No inadequactos were identified.

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l i 7.0 Review of Plant Events

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The inspector reviewed events that occurred during the inspection to verify continued safe operation in accordance with the Technical Specifications and regulatory requirements. The following items, as applicable, were l considered during the inspector's review of operational events: descrip-  :

j' tion of event, including cause, systems involved, safety significance, i facility status, and response of safety systems; operational parameters were verified to remain within approved limits; details relating to release  :

of radioactive material; verification of correct operation of automatic equipment, based on a review of the plant logs, as applicable; verifica-tion of proper manual actions by plant personnel and adherence to approved operating and emergency procedures; and, notification to the NRC and off-site agencies per 10 CFR 50.72.

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7.1 An inadvertant scram signal occurred at 12:45 P.M. on October 7, 1985  ;

while I&C technicians were removing relays for the Automatic Scram ,

Air Header Dump System per EDCR 84-410. There was no control rod '

motion since all rods were already inserte No fuel was in the reactor at the time and the RPS system was not required to be operabl The inspector reviewed the steps from the EDCR 84-140 installation i and test (!&T) procedure that caused the scram, and determined that I there was no personnel error involved. The I&T procedure recognized '

l that a half scram would be produced but failed to recognize .that the i SRM shorting links were removed previously during the outage as a i

! prerequisite for refueling operations. In failing to recognize the  !

removal of the shorting links, the I&T procedure failed to recognize [

the loss of coincidental scram logic on the SRM instrumentatio Therefore, the actions taken as prescribed by EDCR 84-410 cuased the !

scram signal. The licensee reviewed the EDCR after the event and  !

amended the procedures to prevent recurrence. The inspector deter-  !

mined the actions taken were acceptabl {

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Reactor coolant water was discharged from the hydraulic control units l when the scram signal was generated. The radiological controls and '

l cleanup efforts from the resultant contamination are discussed further '

l in paragraph 6 above. The inspector reviewed Switching and Tagging .

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Order 675, OP 2111 - Control Rod Drive System, and OP 1123 - Reactor Vessel Setup for Pipe Replacement, to determine how the spill occurre Prior to the event, the HCUs were partially isolated with the accu-  !

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mulators vented per OP 1123 which left the HCU 107 valves ope l Tagging Order 85-675 opened the HCU 104 and 101 valves to allow con-

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i tinued cooling water flow through the drive' The HCU #107 valves  :

were not addressed in the original tagging der. Operations Crew

'C' started work on the tagging order on OctoDer 6,1985 and closed

the HCU 107 valves to comply with OP 2111,Section II.C.2. Opera-i tions Crew 'A' finished work on the tagging order on October 7, 1985, but opened the HCU #107 to agree with the instructions of OP 112 ;

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Completion of this activity left the HCU 101 and 107 valves ope The scram signal caused the scram inlet valves to open (HCU 126s)

which created the following flow path: CRD - HCU 101 - Scram inlet 126 - HCU 107 - Reactor Building. The flow path was blocked upon reset of the scram signal. The licensee subsequently took actions to close the HCU 107 valves (on October 7,1985) and add them to Tagging Order 675 (on October 10,1985).

The inspector determined that OP 2111 prescribes an HCU valve lineup that allows the HCU 101,104 and 107 valves to be open, but does not address the concern of a open flow path that would be created by a scram signal. OP 1123 addressed the need to open the 107 valves ini-tially to depressurize the HCU once it was isolated, but failed to provide clear instructions regarding the desired final position of the 107 valves. Further, OP 1123 did not recognize that the 107s did not have to be left open since the CR0 pumps would not be used for CR0 cooling. The inspector determined that the spill occurred due to a lack of coordination between the above procedure The inspector discussed his concerns regarding the incident with the Operations Supevisor on October 15, 1985, who stated that the pro-cedure problems had been noted and would be addressed. This item is open pending the completion of licensee actions to revise the pro-cedure(s) and subsequent review by the NRC (IFI 85-30-04).

The licensee did not report the inadvertant scram signal per 10 CFR 50.72 since there was no rod motion and the RPS was not required to be operable at the time. This item is discussed further in section 9 below. A written report per 10 CFR 50.73 will be made. No inade-quacies were identified. This item is open pending receipt of the LER for the October 7, 1985 scram signal and subsequent review by the NRC(IFI 85-30-05).

7.2 The inspector reviewed the licensee's planning and actions completed in advance of the arrival of Hurricane Gloria in the area on September 27, 198 Refueling activities were in progress at the tim Contingency actions included: verification that diesel fuel oil sup-plies were adequate; supplying station power by back feeding through the main transformer and using the startup transformers as a standby supply; stopping outage work releasing non-essential personnel from duty at the site; establishing wind speed limits (40 mph) for the cessation of reactor defueling activities to assure the continued availability of secondary Containment integrity While fuel moves Were in progress; verification of the availability of the Vernon Hydro l Station as a backup source of power; and, securing loose objects i

around the sit _ _ _ _ _ _ _ _

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A disorganized storm center passed the vicinity of the site at about l 4:00 P.M. on September 27, 1985. Average wind speed increased to about 25 mph, with wind gusts below 40 mph. Wind speeds in excess of i 75 mph would have required the declaration of an Unusual Event in accordance with the emergency plan. No emergency was declare Plant operators ended a storm alert status at 8:00 P.M. after the storm left the area. No damage occurred at the site.

The inspector identified no inadequacies in the licensee's plans or action .0 Refueling Tests and Activitites Plans and procedures established by the licensee in preparation for re-fueling operations were reviewed to verify compliance with regulatory requirements. The status of plant systems were observed and completed test procedures were reviewed to verify required surveillances were com-pleted. Refueling activities in progress were reviewed for compliance with established procedure .1 Outage Planning and Reload Licensing The inspector reviewed the 1985 Refuel Outage Plan which provided the licensee's overall planning guide for the outage, including the re-vised plant organization and reporting lines for contractor control, schedule, work lists, design changes and modifications and required l surveillances. The outage manual plans and schedules were used as a

planning guide for NRC inspection of outage activities. No inade-l quacies were identified.

l The inspector noted that the licensee's relocd analysis for Cycle XII was still in progress and is expected to be completed by December, 1985. Upon completion of the analysis, the licensee will determine whether the core reload can be completed under the provisions of 10 CFR 50.59, or if a Itcense amendment is required for subsequent reac-tor operation This item is open pending completion of the 11-l consee's analysis and subsequent review by the NRC (IFI 85-30-06).

8.2 Refueling _ Procedures The following procedures were reviewed in preparation for witnessing the indicated activit The procedures were approved in accordance with the licensec's administrative requirements and were found technically acceptable to accomplish the intended tas AP 1000, Refueling, Revision 9, 10/3/83 OP 1410, Fuel Loading, Revision 13, 8/12/85 <

OP 1100, Fuel Platform Operation, Revision 11, 3/30/84

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OP 1101, Fuel Assembly Movement, Revision 11, 4/17/84 OP 4102, Refuel Outage Tests, Revision 11, 8/21/85 1 .

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No inadequacies were identifie .3 Refueling Prerequisites and Periodic Tests The inspector reviewed test results, completed check lists and logs to verify that refueling prerequisites established by procedures and the technical specifications were completed as require The following items were reviewed during the period from September 26

- October 10, 1985: (1) the requirements of Technical Specification 3.12 governing refueling interlocks, core monitoring, reactor mode switch position, fuel movement, spent fuel pool temperature, SRM coincidence logic, cavity water level, spent fuel pool temperature, and reactor building integrity; (2) the requirements of Technical Specification 3.5.H 4 regarding core spray, residual heat removal, diesel generator and condensate storage tank operability; and, (3)

the completion of prerequisite and periodic tests per OP 4420 - SRM response checks, OP 1410 - refueling prerequisites, two rod interlock functional tests pwer OP 4102, and, refueling tool checks per OP 410 No inadequacies were identifie .4 Witness of Refuel Operations Fuel handling and associated activities were observed during the period from September 26 - October 10, 1984. Activities were moni-tored in the control room and on the refueling floor during both day

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shifts and back shifts. Activities were observed for the movement of fuel bundles LJP 243, LJP 192, LJZ 069 and LFP 23 '

The following items were verified during inspector observations: (1)

approved procedures governing the activity were followed and pre-

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requisites were established and maintained; (2) applicable procedures for SNM accountability were in use, followed and maintain;J; (3) fuel status boards were established and maintained on the refuel floor and in the control room; (4) control room and refuel floor staffing met regulatory requirements; (5) source range monitors responded as ex-pected during fuel transfers and control room operators monitored detector response after geometry changes; (6) health physics controls were established and followed; and, (7) a minimum of two means of communications were maintained between the control room and refuel floor and were used to coordinate refuel floor and control room activities during fuel move No inadequacies were identifie .5 Spent Fuel Pool Activities

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i The inspector noted through procedure reviews and direct observations

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at various times during the inspection period that the following con-trols were established for activities associated with the spent l

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< . fuel pool and reactor cavity: (1) water level and temperature were maintained as required; (2) housekeeping and control of loose objects over the cavity and fuel pool were established and maintained; (3)

fuel pool clarity was acceptable; (4) the spent fuel cooling system was operable and adequate for. decay heat removal after a full core

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discharge; and, (5) process and area radiation monitors were operabl No inadequad,ies were identifie .

8.6'. Following of ' Findings and Events

'8. During transfers of double blade guides from the refuel floor to the spent fuel pool on September 26, 1985, a guide hung up on an empty storage rack as it was lowered into the spent fuel pcol. The guide came to rest in a near horizontal position over empty fuel- storage racks before workers realized it was hung up and stopped the crane. Activities were stopped pending review of the evolution by supervisory personnel. The guide did not contact spent fuel and there was no damage to the fuel rack or the guide. The worker in charge of crane operations was re-

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lieved from refuel floor duties and assigned work elsewher Blade guide transfer activities resumed :and continued for the remainder of the core off load operations without further in-ciden No inadequacies were identified in the licensee's response to the inciden . During an-attempt to lower fuel bundle LY 7005 into Spent Fuel Pool (SFP) location U48 at 10:55 P.M. on September 28, 1985, the bundle became bound in the storage cell prior to reaching the full down position. The bundle had been transferred from reac-tor location 5-26 and it is scheduled to be used again in cycle XII. The fuel bundle was transferred to prep machine #2 pending further inspections and evaluations of its acceptability for

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reuse by the licensee's reviews will be followed by the inspec-4 s tor on a subsequent inspection (IFI 85-30-07).

Licensee examination of storage cell #48 identified a piece of LPRM that had fallen into the spent fuel pool during previous cutting operations. The licensee had looked for the LPRM piece e at that time, did not find it, and had incorrectly concluded

that the object had fallen underneath the spent fuel storage

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racks. Following the discovery of material in location U48, a complete inspection of every empty storage cell was completed by

' September 30, 1985, which revealed additional debris in storage 1 location R36. Bundle LJZ 942, scheduled for storage in location R36, was placed temporarily in prep machine #1. The material in both storage locations was subsequently retrieved and an inspec-tion of cell R36 with underwater video equipment revealed no damage had occurred. The fuel bundles in the prep machines were transferred back to the designated SFP storage locatio No

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inadequacies were identified regarding the licensee's~ response to the even N 3-

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8. The licensee completed examinations of SRM and IRM dry tubes in accordance with the recommendations of GE SIL No. 409 during the outage. The reactor vendor recommended the examinations be conducted because of cracks in the upper portion of the dry tubes that were identified at other facilities. SIL #409, dated June 19, 1984, suggested that the most likely cause of the iden-tifivd cracking was either irradiation assisted stress corrosion cracking, or flow induced vibrations during refueling and main- '

tenance outages. The licensee first inspected the tubes during the 1984 outage and no cracks were observed at that tim The preliminary results of the' underwater visual inspection of the SRM and IRM dry tubes reported on October 6,1985 indicated that 6 of the 10 tubes have cracks of the type previously iden-tifie The licensee plans to replace all SRM and IRM dry tubes during the present refueling outag Continued licensee inspection of IRM 'B' identified ' rub' marks along the length of the tube below locations where problems had been noted at other facilities. The ' rub' marks developed into an indentation, which split open into a crack in the lower sections of the tube. The significance of the findings is that it is unique to VY in that the crack violated the pressure boun-dary of the IRM dry tub Licensee review of the finding and the cause of the crack was still in progress at the conclusion of the inspection. The licensee is considering the possibility that the IRM tube was damaged during insertion of a double blade guide during this outage. The results of the licensee's evalua-tions and corrective action plans will be reviewed on a subse-quent inspection (IFI 85-30-08).

9.0 Technical Specification Requirements The following items regarding licensee compliance with technical specifi-cation and regulatory requirements warranted followup by the inspecto .1 The preliminary results form 10 CFR 50 Appendix J Type 'C' contain-ment local leak rate testing conducted during the inspection period identified the following valve failures: MSIV-86C, RWCU-15, CRD-181, MSD-77, CRD-77, CRD-412A, FDW 96A, CRD 413A, CRD 413B and CA 89 The leakage measurements on the FDW 96A valve was 10 SCFM at 0.4 psi, and undeterminable at 44 ps A potential reportable occurrence report was issued on September 26, 1985 based on the evaluation that the FDW 96A leakage exceeded the CFR 50 leakage limits. .The test results from all valves indicated that the Appendix J limit of 14.74 lbm/hr was exceeded, which does not meet the requirements of Techni-cal Specification 3.7.A.3 (less than 0.8 weight percent per day at 44 psig).

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The licensee plans to evaluate the failures and to repair the valves prior to startup fecm the current outage. A second local leak rate test will be cor. ducted following completion of the repair The inspector noted that the FDW 96A (outboard) check valve had failed the leak rate test on two previous occasions (reference LERs 84-11 and 83-10). This item is unresolved pending: (1) licensee reporting of the results of the local leak rate testing per 10 CFR 50.73; (2)

completion of licensee actions to evaluate and repair the identified valve failures; and, (3) subsequent NRC review of licensee actions to evaluate and correct the failure mechanism for the F0W 96A valve (URN 85-30-09).

9.2 During a meeting on October 1,1985, the licensee notified the in-spector of his intent to use the NES-5 cask in the spent fuel pool at some future date during the outage to load radioactive waste for shipment offsit The licensee reviewed the bases for Technical Specification 3.7.C.1.d and took the position that reactor building integrity would not be required during the cask handling operations, since the NES-5 cask will not contain fuel and no irradiated fuel assemblies would be moved. The NES-5 cask is scheduled to be onsite and used in the Reactor Building in December, 1985, and secondary containmut integrity requirements will be relaxed in October, 1985 to facilitate pipe replacement wor The inspector noted that the dimensions for the NES-5 cask are 80 inches tall by 50 inches in diameter, with a maximum loaded weight of 50,506 lbs. The cask will be handled by the 110 ton Reactor Building crane which has a dual load path for rigging redundanc The NRC staff approved the design of the lifting device for the cask in a SER dated July 1, 1985. The cask will be used inside the SFP twice to load 18 canisters contained in two liners. The cask will not traverse spent fuel by following the prescribed movement paths. Based on the above, a cask drop incident is considered incredibl The inspector noted that the licensee's position was consistent with the literal reading of the specification, but questioned whether the licensee's position was in agreement with the intent of the specifi-cations to provide multiple levels of safeguards to mitigate the con-sequences of a cask drop accident which could put spent fuel in the adjacent fuel racks at risk. No further action by the licensee is required at this tim This item is open pending further staff review of the intent of Technical Specification 3.7 and the licensee's position (UNR 85-30-10).

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9.3 During a meeting on October 3, 1985, the licensee presented his position regarding the need to make 10 CFR 50.72 notifications for

' scram events' or inadvertent ESF actuations that occur with the reactor defuele _

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The licensee stated that one hour resorts under CFR 50.72 (b)(1)(iv),

or four hour reports under 50.72(b)(2)(ii) would not be made to the

'NRC Duty Officer, since the ESF systems are not required to be oper-able in the current plant configuration and such actuations could not result from ' valid' signals. The policy would remain in effect until fuel is ready to be reloaded in the reactor, or until the applicable system is required to be operable (for example, secondary containment requirements). The licensee stated that the occurrence of inadvertent actuations would still be logged in the control room log book and the appropriate followup actions would be taken to investigate the inci-dents. The licensee stated that the events would still be reported under the requirements of 10 CFR 50.7 The inspector noted the licensee's position and identified no inadequacie .0 Recirculation Pipe Replacement The inspector reviewed portions of the following licensee and contractor documents regarding the recirculation pipe replacement program in prepara- ;

tion for further review of the pipe replacement work, and to verify the i procedures were prepared in accordance with the administrative ' require-ments:

EDCR 85-1, Recirculation /RHR Piping Replacement MK Procedure FQP-7.1, Receipt Inspection, Revision 0, 5/7/85 EDCR 85-1, Installation and Test Procedure, Draft EDCR 85-1 S1, Specification for Procurement of Nuclear Grade Stainless Steel Piping EDCR 85-1 S3, Specifications for Replacement of Recirculation and RHR Systems Preservice Inspection Plan for Recirculation Pipe Replacement Program, Draf t Certified Material Test Reports for Piece RHR-30-2-1 Procedure FQP-7.1 was found to be consistant with the requirements of ANSI Standard N45.2.2-1978 for the inspection of material attributes. The in-spector also accompanied Region I inspection personnel (reference Inspec-tion Report 85-32) during a review of replacement RHR/ Recirculation piping in the MK storage buildin NRC review of the recirculation system design change will continue on subsequent routine inspections. No inadequacies were identifie .0 Management Meetings Preliminary inspection findings were discussed with licensee management periodically during the inspection. A summary of findings for the report period was also discussed at the conclusion of the inspection.