IR 05000271/1981018
| ML20038B430 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 11/20/1981 |
| From: | Collins S, Gallo R, Raymond W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20038B426 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.B.4, TASK-2.E.4.1, TASK-2.E.4.2, TASK-2.K.3.13, TASK-2.K.3.15, TASK-2.K.3.27, TASK-TM 50-271-81-18, IEB-81-02, IEB-81-2, IEC-81-02, IEC-81-04, IEC-81-10, IEC-81-13, IEC-81-2, IEC-81-4, NUDOCS 8112080284 | |
| Download: ML20038B430 (31) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE'0F IN5PECTION AND ENFORCEMENT TERA 50-271 Region I 810928 811005 Report -No. 81-18 811016 Docket No. 50-271 License No. DPR-28 Priority Category C
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Licensee:
Vennont Yankee Ncclear Power Corporation 1671 Worcester Road Framingham, Massachusetts 01701 Facility Name:
Vennont Yankee Inspection at:
Vernon, Vermont Inspection conducted:
October 6-November 2,_1981 Inspectors:
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W. J. Raymond[/SenioriResident Ir.spector da'te sir:ned M
IE7/81 S. J. Collins, Resident Inspector date signed date signed Approved by:
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fpj R. M. Gallo, Chief, Reactor Projects date sfgned Section IA, Projects Branch #1 Insoection Summary:
Inspection on October 6-November 2, 1981 (Report No. 50-271/81-18)
Areas Inspected:
Routine announced inspection on regular and backshifts by Resident
' Inspectors of: action taken on previcus inspection findings; IE Bulletin and Circular followup; review of shift logs and operating records; plant tours; refueling activities; observations of physical security; review of periodic and special reports;, surveillance testing; maintenance activities; inspector followup of events; in-office review of licensee event reports; insoector actions based on a review of the status of licensee implementation of NUREG 0737 requirenents;and, inspector actions based on Region initiated inspection requests. The inspection involved 153 inspector hours onsite by two resident inspectors.
Results: Of the fourteen areas inspected, no items of noncompliance were identified.
Region I Form 12 (Rev. April 77)
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DETAILS 1.
Persons Contacted The below listed technical and supervisory level personnel were among those contacted:
Vermont Yankee Nuclear Power Corporation Mr. D. Allen, Reactor Engineer Assistant Mr. L. Anson, Plant Training Supervisor Mr. E. Bcwles, Training Supervisor Mr. R. Branch, Operations Supervisor Mr. F. Burger, Quality Assurance Coordinator Mr. B. Buteau, Reactor Engineering and Computer Supervisor Mr. P. Donnelly, Instrument and Control Supervisor Mr. R. Kenny, Engineer, Assessment Coordinator Mr. D. Girroir, Mechanical Engineer Mr. L. Goldthwaite, Instrument and Control Foreman Mr. S. Jefferson, Technical Services Superintendent Mr. D. LaBarge, Shift Supervisor Mr. B.' Leach, Health Physicist Mr. M. Lyster, Operations Superintendent
- Mr. W. Murphy, Plant Manager Mr. J. Pelletier, Assistant Plant Manager Mr. D. Reid. Engineering Support Supervisor Mr. S. Vekasy, Senior Systems Engineer
- denotes those present at management meetings held periodically during the inspection.
2.
Action Taken on Previous Inspection Findings a.
(Closed) Unresolved Item (50-271/80-07-01):
Fire Brigade Training -
Fire Fighting Practice Session. The inspector reviewed licensee procedure AP 3700, Fire Training, Revision 4, October 16, 1981, which identifies and establishes training requirements for implementation of the Fire Protection Plan. Section C. of the procedure, Off-Site Firefighting Training (Fire Brigade), specifies the requirements for firefighting training with actual fires as follows:
C.
Off-Site Firefighting Training (Fire Brigade)
1.
Firefighting training with actual fires will take place at an off-site facility on an annual basis.
NOTE:
Those personnel who are hired subsequent to the hands-on annual training will be considered as qualified Fire Brigade Members with the class-room training as outlined above until the next scheduled hands-on off-site schoo ~
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2.
The training will include:
a.
Structural firefighting b.
Cable tray fires c.
Flansnable fluid fires d.
Flammable gas fires e.
Use of self-contained breathing apparatus f.
Hose and associated equipment handling g.
Search and rescue techniques h.
Fire extinguisher operation The procedure also specifies that the Fire Brigade members shall receive training as outlincd in Part C on an annual basis and a Fire Brigade Training Qualification Checklist will be maintained on VYAPF 3700.01. The inspector reviewed the 1981_ agreement between Fire Service Instuctor Consultants, Inc. and Vermont Yankee Nuclear Power Corporation which outlined the course of instruction which included:
1.
Chenistry of fire-extinguishers A, B, C and D fires (classroom and field)
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Firebehavior(classroom)
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Anatomy of ventilation (classroom and field)
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Basic ladder fundamentals (classroom and field)
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Firefighting and fixed protection systems (classroom)
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Self contained breathing apparatus (classroom and field)
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Hazardousmaterials(classroom)
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Tactics and strategy for nuclear power plants (classroom and field)
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Flammable liquids and gases (typical to site) (classroom and field)
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Cable tray fires (classroom and field)
11.
Record file fires (classroom)
The inspector also reviewed the attendance records, VYAPF 0004.01, of five current Fire Brigade members and detemined that they had completed the hands-on training as specified in AP 3700. This item is closed.
b.
(Closed) Follow Item (50-271/80-07-03): Update Procedure AP 3023 Section E - Number of Fire Drills. The inspector reviewed VYAP 3700, Revision 4, dated October 16, 1981, Fire Training which supersedes AP 3023, the inspector noted that Section F.,
Fire Drills, contains the requirement that sufficient fire drills will be held on an annual basis for each member of the fire brigade, so that each receives two drills per year. This item is closed.
c.
(Closed) Follow Item (50-271/80-07-04):
Preconnect Hose Lines to Hose Station RX-5.
During the inspection it was noted that a single
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failure of the water supply system can result in loss of both the cable penetration area sprinkler system and hose station RX-10 which provides manual backup for this area. The licensee had provided a backup by installing a 2h inch hose outlet at hose station RX-5, located approximately 300 feet from the affected area. The inspector noted that adequate lengths of 2 and ih inch hose were not provided at the hose station. As a followup, the inspector reviewad this item with the plant Fire Protection Coordinator.
Actual distance between RX-5 hose station and the affected area (column H-11X, 252 foot level) is approximately 175 feet in lieu of 300 feet. Trie licensee reports that 350 feet of 3-inch hose with 2h inch couplings is stored in the turbine building Foam Equipment Cabinet which is located outside the reactor building entry doors on the same building elevation at stations RX-5 and RX-10. This hose length is available to use with station RX-5 as a backup for RX-10 and the cable penetration area sprinkler system.
The inspector reviewed VYOPF 4020.06, Monthly Fire Brigade Room Equipment Surveillance, dated October 15, 1981, and verified that the availability of the backup equipment is monitored by plant surveillance. This item is closed.
d.
(Closed) Follow Item (50-271/80-10-05): Scram Discharge Volume Piping Slope. The inspector noted during a tour of the MS Tunnel on October 17, 1981, that the South Scram Discharge Volume Drain line maintains a continuous downward slope as it runs North through the CRD repair room and the MS Tunnel. No loop seals are present in the line. This item is closed.
e.
(Closed) Follow Item (50-271/80-15-11): Follow Rod Drop Events.
The inspector noted by direct observation and through discussions with plant personnel that the affected control rod handling tool would not be used until it had undergone corrective repair. GE had been contacted to provide a design change for the tool. The tool was removed from the spent fuel pool, set aside on the RB 345 foot elevation and tagged to prevent inadvertent use. Control rods that were damaged during the outage have also been set aside i
pending a subsequent evaluation regarding ultimate disposit.ioning.
Fuel assemblies struck by the controi rods were inspected and either stored in the spent fuel pool or returned to the core.
Additional precautionary notes were added to OP lill by issuance of Department Instruction (DI) 81-31. The procedure now requires that the control rod tool terminal swivel be insoected and/or replaced whenever it is suspected that the swivel is stressed during control rod replacen1ent. This item is closed.
f.
(Closed) Follow Item (50-271/80-15-12):
Dropped LPRM Event.
Licensee inspection and evaluation of fuel assenbly LJP 212 found
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it acceptable for subsequent use in Cycle 8.
Examination of the strongback revealed no cause for misoperation. This item is closed.
g.
(Closed)UnresolvedItem(50-271/80-16-01): Personnel Qualifica-tions and Documentation for NDE Examiners. The inspector reviewed Vendor Evaluation Report (VER) No. 8035 dated October 10, 1980, which documented a licensee-performed audit of Peabody Testing Services, (Magnaflux), at the corporate offices. The audit re-vealed unsatisfactory findings for three of the personnel in rela-tion to documentation of previous experience with another employer to, meet Peabody's minimum requirements.
As reported in VER 80-35, one individual was subsequently disqualified by Peabody Testing pending completion of experience obtained at Peabody. He had not been a part of the VY ISI program or performed ISI work for any of the YAEC plants.
A second individual required documentation of experience from employers other than Peabody Testing. This documentation was received and re-viewed by the licensee prior to issue of VER No. 80-35 and his previous experience was determined acceptable.
A third individual required documentation of experience from an employer other than Peabody Testing. VER 80-35 reports this item remained open pending acceptable additional documentation for him.
Vendor Evaluation Report (VER) 80-35-1, dated April 21, 1981, reports that on April 21, 1981, the additional documentation to support his previous radiography experience at his previous employer plus the Peabody cover letter signed by Frank Lent was reviewed by the licensee and found acceptable. VER 80-35-1 closed out the audit item. The inspector had no further questions concerning licensee followup actions on Vendar Evaluation Report No. 80-35.
Inspection Report (IR) 80-16 Item 01 also notes that as a result of VER 80-35 findings, a detailed audit was performed by the licensee's Operational Quality Assurance (0QA) department to speci-fically identify the discrepancies in Peabody Testing inspector training and experience records. The inspector noted in IR 80-16, detail 5., that the audit revealed 25 items of varying severity and that all but three of the items were cleared by the conclusion of IR 80-16 inspection. The inspector reviewed Operational Quality Control Audit Inspection Checklist, 0QA X-1.1, Revision 2, dated September 19, 1980, 00A Inspection No. SI 80-2.
As noted by 0QA inspector signoff on Supplemental Inspection Sheets, 0QA-X-1.2, all items had been reinspected satisfactorily and 0QA Inspection No. VY-SI-80-2 was closed out on August 8, 1981. This item is closed.
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h.
(0 pen)FollowItem(50-271/81-05-01): B Recirc Set Field Breaker.
The B Recirculation Pump was returned to service on March 22, 1981, following inspection and lubrication of the MG Set field breaker.
Inspection of the breaker was scheduled during the refueling outage, as noted by its inclusion on the outage work list. Following reactor cooldown on October 17, 1981, for the start of the refueling outage, the B Field Breaker again failed to open when the Recirc pump was tripped. An Auxiliary cperator was dispatched to the breaker to trip it locally. As in the first incident, the trip solenoid on the breaker was found energized by the operator, indicating that the trip circuitry was working and that the problem appeared to be caused by mechanical binding internal to the breaker. The breaker was subsequently removed for examination. The breaker was examined by the inspector in the company of licensee personnel.
The breaker was manually set and tripped several times with no conditions'noted that would cause a failure.
During a subsequent meeting with the plant manager on November 5, 1981, the inspector expressed his concerns for the repeated failure and the need for corrective actions that would assure reliability of breaker operation, and thus, the associated RPT trip circuitry. The licensee stated that the existing breaker would be replaced during the outage and an operational test conducted to ensure its operability.
This item remains open pending completion of the above actions by the licensee and subsequent review by the inspector.
i.
(Closed) Follow Item (50-271/81-05-02): B Recirc Field Breaker LER.
Licensee Event Report 50-271/80-10 was submitted by letter dated April 15, 1981, to describe the event and scheduled corrective actior.s. This item is closed.
j.
(Closed) Unresolved Item (50-271/81-05-04): STA Training Completion.
The inspector reviewed course outlines, attendance records, course certificates and instructor resumes for training completed by the seven Nuclear Safety Engineers from February 1981-May 1981. The Nuclear Safety Engineers started shift duty in June 1981. This item is closed, k.
(Closed)FollowItem(50-271/81-05-05): Overtine Limits. Subsequent NRC Staff evaluation of the limits established by AP 0036 concluded that the policy on overtime limits is acceptable. This item is closed.
1.
(Closed) Unresolved Item (50-271/81-08-05):
Issue AP 0710/0711.
AP 0710, Initial Operator Licensing,and AP 0711, Licensed Operator Retraining were approved and issued on July 24, 1981. This item is closed.
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m.
(0 pen) Unresolved Item (50-271/81-13-03): RHR V10-31B Motor Mount Failure - PORC Evaluation and LER Issue. The inspector reviewed VVY-81-200. August 14, 1981, Reportable Occurrence No. R0 81-20/3L which provided an event description, cause description and corrective actions. The LER nctes that an evaluation of the basis for sizing the mounting bolts will be investigated with the Vendor. The inspector reviewed Plant Operations Review Committee Meeting _ Minutes from Meeting No. 81-37, August 12, 1981, and noted that mounting bolt evaluation is listed as PORC follow item 81-37-01 assigned to the Maintenance Department. This item remains open pending completion of:
(1) the licensee's actions in regard to PORC follow item 81-37-01, and, (2) documentation of the use of sin;ilar motor mounting bolt modifications on limitorgue vahe operators.
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3.
IE Bulletin Review and Followup
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Licensee respor.ses and actions taken for the IE Bulletins listed below were reviewed to verify that:
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the bulletins were received onsite and reviewed for applicability
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to the facility; I
bulletin action items, if applicable, and identified problems were
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appropriately dispositioned; j
corrective actions taken, or planned, were appropriate; and,
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responses to the NRC were accurate and within the time period
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specified in the bulletin.
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Inspector followup on selected bulletins is summarized below. The inspector had no further coment on the subject bulletins, except as indicated below, a.
IEB 81-02, Supplement 1, Failure of Gate Type Valves to Close Against Differential Pressure, dated August 18, 1981 The IEB Supplement extended the concerns over specific gate type valves which have a potential for not closing against differential pressure, to the entire line of W-EMD manufactured motor-operated gate valves.
l By letter FVY 81-130, dated September 4, 1981, VY reported that
the licensee does not have any of the affected valves installed i
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or maintained as spares for installation where they would be required to close with differential pressure across them in safety-related systems.
The inspector determined that the licensee's response adequately addresses the requirements of IEB 81-02, Supplement 1.
This item is closed.
4.
IE Circular Followup The following IE Circulars were reviewed to ascertain if the following actions were taken by the licensee:
The Circulars were received by licensee management.
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A review for applicability was performed.
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For Circulars forwarded to the facility, appropriate corrective
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actions have been taken or are scheduled to be taken as noted below, a.
IE Circular 81-02, Perfomance of NRC-Licensed Individuals While on Duty, dated February 9, 1981 The inspector verified that the licensee received the subject IEC and forwarded the IEC with actions required to the site Operations Supervisor via VYAPF 00LB.01 on February 17, 1981. VY internal memorandus dated October 6, 1981, File 10.0 documents departmental review of the IEC. This item is closed.
b.
IE Circular 81-04, The Role of Shift Technical Advisors and Importance of Reporting Operational Events, dated April 30, 1981 The inspector verified that the licensee received the subject IEC and forwarded the IEC with actions required to the site Operations Supervisor and STA Supervision via VYAPF 0028.01 on May 12, 1981.
VY internal memorandums dated June 1, 1981, File 13.1, and August 26, 1981, File 10.0, document departmental review of the IEC and assign responsibility for a wording change to AP 0150 under the " Shift Supervisor Responsibility" Section. This item is closed.
c.
IE Circul:.r 81-10, Steam Voiding in the Reactor Coolant System During Decay Heat Removal Cooldown, dated July 2, 1981 Inspector review verified this IEC is not applicable to Vermont Yankee.
This item is close.
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d.
IE Circular 81-13, Torque Switch Electrical Bypass Circuit For Safeguard Service Valve Motors, dated September 25, 1981 The inspector verified that the licensee received the subject IEC and forwarded the IEC with actions required to the Assistant Plant Superintendent via VYAPF 0028.01 dated October 1, 1981. The licensee determined that the issues raised by IEC 81-13 have previously been addressed. This item is closed.
5.
Shift Logs and Operating Records a.
The inspector utilized the following plant procedures to determine the licensee established administrative requirements in this area in preparation for review of various logs and records.
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AP 0831, Plant Procedures, Revision 7, dated Augt'st 17, 1981 AP 0150, Responsibility and Authority of Operations Department
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Personnel, Revision 16, dated October 21, 1981 AP 0153, Maintenance of Operations De;artment Logs, Revision 9,
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dated August 17, 1981
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AP 0140, VY Local Control Switching Rules, Revision 5, dated October 16, 1981 AP 0020, Lifted Lead / Installed Jumper Request Procedure,
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Revision 4, dated October 16, 1980 AP 0021, Maintenance Regrests, Re*/ision 9, dated September 25, 1980
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AP 0030, Plant Operations Review Comittee, Revision 6, dated
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January 7, 1980 The above procedures, Technical Specifications, ANSI N18.7-1972
" Quality Assurance Requirements for Nuclear Powe.r Plants" and 10 CFR 50.59 were used by the inspector to determine the accepta-bility of the logs and records reviewed.
b.
Shift logs and operating records were reviewed to verify that:
Control Room logs and surveillance sheets are properly
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completed and that selected Technical Specification limits were met.
Control Room log entries involving abnomal conditions pro-
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vide sufficient detail to communicate equipment status, lockout status, correction and restoration.
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Log Book reviews are being conducted by the staff.
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Operating and Special orders do not conflict with Technical
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Specifications requirements.
Jumper (Bypass)logdoesnotcontainbypassingdiscrepancies
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with Technical Specification requirements and that jumpers are properly approved prior to installation.
c.
The following plant logs and operating records were reviewed periodically during the period of October 6-November 2, 1981:
Shift Supervisor's Control Room Log
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Hight Order Book Entries
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Health Physics Log - Refueling Floor
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Safety Related Maintenance Rquests
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Control Room Operator'Round Sheet
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Auxiliary Operator #1 Rounds Sheet
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Equipment Status Log
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RE Log Typer-Core Perfonnance Log
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Control Room Chemistry Log Sheets
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No items of noncompliance were identified.
d.
Certain items noted during reviews of licensee logs and records required additional followup, as discussed below.
(1) On October 5, 1981, the operating coil of relay K49D failed.
The failure was identified when control room personnel noted the relay was smoking. The relay was de-energized by placing trip unit 17-452B in test and a fire watch was established.
Relay K49D is part of the isolation logic _for groups 3 and 5 in RPS Channel II for the Reactor Building Ventilation Exhaust.
The channel test switch was subsequently placed in BYPASS to allow repair of the channel. Relay K49D was subsequently replaced.
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The insP tor reviewed licensee actions and the o>erating status the RB Ventilation monitors to verify t1e Technical Specifw.ition 3.2 requirements were met.
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No items of noncompliance were identified.
(2) uuring LPRM replacement at 9:45 P.M. on October 26, 1981, the middle section of a spent LPRK popped above water level in the spent fuel pool. The incident occurred as the LPRM was being bent in preparation for cutting, and apparently " sprung"'
vertically as it was bent horizontally. The bridge operator i;sediately pushed the LPRM unde mater. A Reactor Building Group 3 isolation was generated from the Refuel Zone Radiation monitor. The Standby Gas Treatment System operated properly.
The inspector interviewed the HP technician who was on duty when the incident occurred. Although he was monitoring the evolution with a survey meter, no radiation readings were obtained due to the short time the LPRM was above water.
Individuals working on the LPRM received no appreciable dose, as read by their pocket doismeters. The inspector reviewed the dose infomation recorded by the work party on RWP 81-870 and noted a maximum individual exposure of 30 mrem for 6 to 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> work period.
No items of noncompliance were identified.
6.
Plant Tour The inspector conducted a tour of accessible areas of the plant including the Control Room Building, Turbine Building, Reactor Building, Diesel Rooms, Intake Structure, Security Gate Houses 1, 2 and Alann Stations, Radwaste Building and Control Point Areas.
a.
Monitoring Control Room Panels Routinely during the inspection period, the inspectors conducted rc-views of the control room panels. The following items were reviewed to determine the licensee's adherence to Licensee Technical Specifica-tion - Limiting Conditions for Operation and to verify the licensee's adherence to approved procedures.
Switch and valve positions required to satisfy LC0's, where
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applicable.
Alarms or absense of alams. Acknowledged alarms were reviewed
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with on shift licensed personnel as to cause and corrective actions being taken where applicabl.
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l Review of " pulled alam cards" with on shift personnel.
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Meter indications and recorder values.
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Status lights and power available lights.
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Front panel bypasses.
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Computer printouts.
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Comparison of redundant readings.
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No items of noncompliance were identified. Except as noted below, the inspector had no further conraents in this area.
The inspector noted on October 6, 1981, that Temperature Recorder 27, 1979, TR 16-19-40 on CRP 9-41 was last calibrated on December The inspector as indicated by a calibration sticker affixed to it.
notified licensee personnel of the finding, who confimed that the recorder had exceeded the calibration frequency of one year specified 15, 1979.
in GP 5350, Calibration of Plant Recorders, dated March 16-19-40 was missed in 1980 apparently because Calibration of TR Actions were it was not included on the OP 5350 recorder list.on October 7,1981, 16-19-40 taken by the licensee to calibrate TR and include the recorder in the OP 5350 listing.
The inspector reviewed about 30 other recorders and indicator.s inFailure to cali-the control room and noted no other inadequacies.
brate TR 16-19-40 in accordance with OP 5350 requirements appears to be an isolated occurrence.
The inspector had no further connents on this item, b.
Radiological Controls posting Radiation controls established by the licensee, including:
of radiation areas, radiological surveys, condition of step-off pads, and disposal of protective clothing were observed for conformance with the requirements of 10 CFR 20 and AP 0503, Establishing and Posting Controlled Areas, OP 4530, Dose Rate Radiation Surveys and OP 4531, Radioactive Contamination Surveys.
Confirmatory surveys were conducted in the following areas to Reactor Building general areas -
verify licensee posted results:The inspector witnessed a survey of the 345 foot all elevations.
elevation of the Reactor Building by licensee personnel on November 2, 1981. Data was recorded on VYOPF 4530.07 and survey meter VY 2406 (R0-2A) was within its calibration interval.
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Review of " pulled alarm cards" with on shift personnel.
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Meter indications and recorder values.
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Status lights and power available lights.
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Front panel bypasses.
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Computer printouts.
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Comparison of redundant readings.
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No items of noncompliance were identified.
Except as noted below, the ia.spector had no further comments in this area.
The inspector noted on October 6, 1981, that Temperature Recorder TR 16-19-40 on CRP 9-41 was last calibrated on December 27, 1979, as indicated by a calibration sticker affixed to it. The inspector notified licensee personnel of the finding, who confirmed that the recorder had exceeded the calibration frequency of one year specified in OP 5350, Calibration of Plant Recorders, dated March 15, 1979.
Calibration of TR 16-19-40 was missed in 1980 apparently because it was not included on the OP 5350 recorder list. Actions were taken by the licensee to calibrate TR 16-19-40 on October 7, 1981, and include the recorder in the OP 5350 listing.
The inspector reviewed about 30 other recorders and indicators in the control room and noted no other inadequacies. Failure to cali-brate TR 16-19-40 in accordance with OP 5350 requirements appears to be an isolated occurrence.
The inspector had no further comments on this item.
b.
Radiological Controls Radiation controls established by the licensee, including: posting of radiation areas, radiological surveys, condition of step-off pads, and disposal of protective clothing were observed for confomance with the requirer.ents of 10 CFR 20 and AP 0503, Establishing and Posting Controlled Areas, OP 4530, Dose Rate Radiation Surveys and OP 4531, Radioactive Contamination Surveys.
Confimatory surveys were conducted in the following areas to verify licensee posted results:
Reactor Building general areas -
all elevations. The inspector witnessed a survey of the 345 foot elevation of the Reactor Building by licensee personnel on November 2, 1981. Data was recorded on VYOPF 4530.07 and survey meter VY 2406 (R0-2A) was within its calibration interval.
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Peridically, Radiation Work Permits were reviewed by the inspector to verify conformance with licensee procedure AP 0502, Radiation Work Permits.. Controls estabiished in accordance with the following RWPs were reviewed: RWP 81-821, 824, 817, 838, 865, 941 and 910.
Except as noted below, the inspector had no further comments in this area.
Upon exiting the Refuel Floor on October 19, 1981, a licensee con-tractor noted his 0-500 mrem pocket dosimeter read offscale high.
During discussions with the individual, the inspector noted he had been part of a work party working inside the vessel cavity under RWP 81-870. The inspector reviewed the sources of radiation present in the work area, along with licensee survey results of the area.
The above information, along with doses received by other members of the work party indicated that the individual's dosimeter reading was erroneous. The licensee pulled and read the individual's TLD to confim the above conclusion.
No items of noncompliance were identified.
c.
Plant Housekeeping and Fire Prevention Plant housekeeping conditions, including general cleanliness and storage of materials to prevent fire hazards were observed in all areas toured for conformance with AP 0041, Plant Fire Prevention and AP 6024, Plant Housekeeping.
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d.
Fluid Leaks and Piping Vibrations Systems and equipment in all areas toured were observed for the existence of fluid leaks and abnomal piping vibrations.
No inadequacies were identified, e.
Pipe Hangers / Seismic Restraints During routine tours of the plant, pipe hangers and restraints installed on various piping systems were observed for proper installation, tension and condition.
No inadequacies were identified, f.
Control Room Manning / Shift Turnover Control Room Manning was reviewed for confomance with the require-ments of 10 CFR 50.54 (k), Technical Specifications AP 0152, Shift
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Turnover, AP 0150, Responsibility and Authority of Operations Depart-ment Personnel and AP 0036, Shift Staffing. The inspector verified, during the inspection, that appropriate licensed operators were on shift. Manning requirements were met at all times. Several shift turnovers were observed during the course of the inspection. All were noted to be thorough and orderly.
No items of noncompliance were identified.
g.
Equipment Tagout and Controls Tagging and removal of equipment from service was observed in areas toured to verify that equipment was controlled in accordance with AP 0140. Tags hung per Order 81-370 were reviewed on October 19, 1981, and found to be proper.
No items of noncompliance were identified.
h.
Primary Containment Isolation Valves Piping between the primary containment and outboard isolation valves was inspected for leakage during tours of the Reactor Building.
No inadequacies were identified, i.
Analyses of Process Liquids and Gases Analyses results from samples of process liquids and gases were re-viewed periodically during the inspection to verify conformance with regulatory requirements. The results of isotopic analyses from reactor coolant, off-gas and stack samples were reviewed routinely from the " Daily Plant Status Report" to verify that Technical Speci-fication Limits were not exceeded and that no adverse trends were apparent.
i No inadequacies were identified.
7.
Refueling Activities Plans and procedures established by the licensee in preparation for re-fueling operatior.s were reviewea to verify compliance with regulatory requirements. Plant systems status was observed and completed test proce-dures were reviewed to verify that required surveillances were completed.
Refueling activities in progress were observed for compliance with esta-blished procedures and regulation.
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a.
Outage Planning and Management
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The inspector interviewed licensee personnel and reviewed documenta-tion to ascertain the methods used to provide outage planning and control. The 1981 Refueling Outage Plan is the governing planning tool used for management of outage activities. The plan describes the overall maintenance / refueling work scope and scheduling; organizational setups and interfaces; shift schedules; itemized work lists and schedules; and, a summary of design changes, modifica-tions ar.d surveillances to be completed. The outage plan in conjunc-tion with daily planning / status meetings provides management control over daily outage activities. The inspector had no further questions in this area.
b.
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 required. The following items were reviewed.
(1) All items of Technical Specification 3.12 which governs refueling interlocks, cora r.onitoring, spent fuel pool water level, reactor mode switch position, control rod maintenance, fuel movanent, trane checks, spent fuel pool temperature and reactor building pressure; (2) The requirements of Technical Specification 3.5.H.4, governing core spray, residual heat removal, diesel generator and conden-sate storage tank operability, ccmpleted October 22, 1981; (3) SRM Response checks, completed per VYOPF 4420.01, completed October 23, 1981; (4) Refueling outage tests completed per OP 4102 cn October 21, 1981; (5) Secondary Containment Surveillance completed per OP 4116 on September 28, 1981 and October 20, 1981; (6) Refueling Prerequisites completed per OP 1410 on October 22, 1981; (7) Standby Gas Treatment System Operability completed per OP 4117 on October 20, 1981; and,.
(8) Red Worth Minimizer Surveillance completed per OP 4450 on October 21, 198.
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Except as noted below, the inspector had no further comments on these items.
The inspector noted that the SRM Operability check procedure re-quires the CR0 to record in VYOPF 4420.01, Section A, the core positions and types of detectors being used. The data recorded for October 22, 1981, indicated " Full In", where as entries under the Daily Response Checks section utilize a preprinted format indicating each SRM detector core position, i.e.,24-37A, 32-21B,16-13C, 08-29D. The inspector inquired as to which data informa-tion was actually required and requested that the operators be infomed of the requirement clarification to provide consistent data for review. The Reactor Engineering Supervisor stated that the actual position of the detector in the core was required and he would infom the eperators via the Night Order Book as to the clarification. The t'nspector reviewed the corrected VYOPF 4420.01 for October 22, 1981, and had no further questions.
c.
Refuel Operations Fuel transfer and related activities were observed at the start of fuel movcunt on October 22, 1981 and periodically thereafter.
Activities associated with fuel movement in the vessel and the spent fuel pool, control rod changeout, LPRM replacement and fuel channeling / inspection were witnessed. Activities were monitored in the control room and on the refuel floor during both day shifts and back shifts. The following items were verified during inspector obse"vations:
(1) approved procedures governing the activity were followed and applicable prerequisites were established and maintained; (2) fuel transfer status boards were established and maintained in the control room and onthe refuel floor; (3) applicable procedures for SNM accountability were in use, followe.d and maintained; (4) communications were maintained between the refuel floor and the control room; (5) SRMs were continuously monitored during times when core geometry was being altered; (6) control room and refuel floor staffing met procedural and regulatory requirements;
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(7) health physics and housekeeping controls, including control of loose objects over the reactor cavity and SFP, were esta-blished and maintained; and, (8) shift turnovers in the control room were conducted in an orderly manner.
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No items of noncompliance were identified. Except as noted below, the inspector had no further coments in this area.
Noise problems were experienced on SRM channel D on October 24, 1981.
Operations personnel conducted a signal-to-noise retio test per OP 4420, found the channel unaccep(MRtable by procedural requirements and issued a maintenance request 81-1205) to effect repairs.
Fuel and control rod change-out activities were continued over the period from October 24 to October 26, 1981, with three of the four SRM channels considered operable.
Licensee personnel stated that continued operation was considered acceptable since, by rotating the core quadrants, en operable SRM channel existed near any core location where alterations were perfonned. SRM D was repaired under MR 81-1205 to replace the preamplifier, change the cable pene-tration and adjust the gain and discriminator settings.
The inspector reviewed the operability of SRM channel D and the licensee's method for complying with Technical Specification 3.12.B.
which requires that a minimum of two SRM channels be operable during core alterations, one in the quadrant where control rods or fuel are being moved and one in an adjacent quadrant.
The Technical Specifications define an SRM channel te be operable when the detector is fully inserted during refueling and indicates a minimum countrate of 3 cps. The latter requirement assures the detector is measuring a neutron flux. SRM operability requirements are verified by licensee procedure OP 4420, which includes the above checks, plus a measurement of the channel signal-to-noise ratio.
Testing per OP 4420 was satisfactorily completed on all channels prior to the start of core alterations; measured signal-to-noise ratios were in excess of the procedure limit 3 cps. SRM channel D testing on October 24, 1981, showed a signal-to-noise ratio of 2.33.
Indicated countrate on the channel was 1E0 cps with the detector
" Full In" and 45 cps with the detector withdrcwn. Thus, although channel D did not meet the OP 4420 criteria for operability, the Technical Specification requirements were met and the channel was capable of measuring neutron flux. The inspector noted that two new fuel assemblies and a single blade guide occupied 3 of the four core locations immediately adjacent to SRM channel D after the failed operability test.
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The inspector reviewed the licensee's practice for operation with an inoperable SFfi channel and stated it would not meet.the intent of the Technical Specification 3.12,B requirements which is to assure SRM channels in the vicinity of core alterations are operable.
The inspector's interpretation of Technical Specification 3.12,B was discussed with the Plant Manager on November 9, 1981. The licensee noted the inspector's coments and stated that current practices would be reviewed and ravised as necessary prior to sub-sequent core alterations.
The inspector had no further comments on this item for the present.
Core monitoring during alterations will be re-examined during sub-sequent inspections.
8.
Observations of Physical Security The inspector made obscrvations, witnessed and/or verified during regular and offshift hours that selected aspects of plant physical security were in accordance with regulatory requirements, the physical security plan and approved procedures, a.
Physical Protection Security Organization observat!ans indicated that a full tire member of the security
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organization with authority to direct physical security actions was present as required.
manning of all shifts on various days was observed to be as
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required, b.
Access Control identification, authorization and badging.
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access control searches, including, when applicable, the use
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of compensatory measures during periods when equipment was inoperable.
escorting.
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c.
Physical Barriers selected barriers in the protected area and vital areas were
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observed and random monitoring of isolation zones was performed, Observation of vehicle searches were made.
inspector tours of gate house 2, the Central and Secondary Alann
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Stations were conducted at random periods.
No items of noncompliance were identifie.
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9.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pur-suant to Tech.wical Specification 6.7 and Environmental Technical Specifica-tion 5.4 were reviewed by the inspector to verify that applicable reporting requirements had been met.
VYV 81-273, Monthly Statistical Report, Month of September,1981,
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dated October 9, 1981.
No unacceptable conditions were identified.
10.
Surveillance Testing a.
Surveillance Test Witness / Data Review The inspector observed or reviewed portions of the following sur-veillance tests to verify that testing was perfomed in accordance with procedures, that results were in conformance with Technical Specifications and procedure requirements, that test instrumentation wascalibrated,thatredundantsystem(s)orcomponent(s)wereavaila-ble for service, that work was being perfonned by qualified personnel, and that activities were in compliance with AP 4000, Surveillance Testing Control.
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OP 4111, CRD System Surveillance, Revision 13, on October 21, 1981 OP 4102, Function Tests of the Refueling Interlocks, Revision 9,
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on October 21, 1981 OP 4030, Type Band C Primary Containment Leak Rate Testing,
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Revision 8, for testing conducted on MSIV 86A on October 17, 1981 and on vacuum breaker V16-19-11B on October 19,1981.
No items of noncompliance were identified.
11.
Maintenance Activities
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The inspector reviewed portions of the following maintenance activities to verify compliance with LC0 requirements where applicable, administrative approvals were proper, approved procedures were utilized, activities were controlled by qualified personnel, equipment certification, and compliance with AP 0021, Maintenance Requests, and AP 0200, Maintenance Program. The following activities were reviewed by the inspector:
i Reactor Vessel Head Detensioning per OP 1200 on October 19, 1981
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Reactor Cleanup System Temporary Piping and Spoolpiece Installation
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per PDCR 81-11 on October 16, 1981.
No items of noncompliance were identifie.
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12.
Inspector Followup of Events The inspector responded to events that occurred during the inspection period to verify continued safe operation of the reactor in accordance
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with the Technical Specifications and regulatory requirements. The following items, as applicable, were considered during the inspector's review of operational events:
observations of plant parameters and systems important to safety
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to confirm operation within approved operational limits; description of event, including cause, systems involved, safety
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significance, facility status and status of engineered safety features equipment; details relating to personnel injury, release of radioactive
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material and exposure to radioactive material;
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verification of correct operation of automatic equipment; verification of proper manual actions by plant personnel; and,
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verification of adherence to approved plant procedures,
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a.
Reactor Trip from 94% FP While testing the turbine control system on October 16, 1981, a reactor trip occurred at 12:50 P.M. after the mechanical pressure regulator (MPR) was placed in service. The trip occurred on high neutron flux caused by pressure oscillations when the MPR failed to take control of the turbine governor valves. A group 1 isolation occurred following the reactor trip, caused by low pressure with the mode switch in RUN.
Inboard MSIV 80C failed to close when the group 1 isolation occurred. SRM Channel B failed to respond following the trip and was declared inoperable.
The inspector witnessed activities in the control room following the trip to verify plant conditions were stabilized, actions taken far inoperable equipment were proper and the response to the scram was in accordance with OP 3100, Reactor Scram Emergency Procedure, Revision 11, dated July 24, 1981. No inadequacies were identified.
SRM Channel B was subsequently repaired and returned to service.
Licensee investigation of MSIV 80C is scheduled during the refueling outage. The reactor was not restarted since shutdown for the 1982 refueling outage was scheduled for 8:00 P.M. on October 16, 1981 Operability of MSIV 80C is required to satisfy Technical Specifica-tion 3.7.D. requirements. Licensee investigation and repair of
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MSIV 80C will.be the subject of inspector review on a subsequent inspection (UNR 50-271/81-18-01),
No items of noncompliance were identified.
13.
In-Office Review of Licensee Event Reports The licensee event ' reports (LERs) listed below were reviewed in the NRC Resident / Regional Office. The reports were reviewed to detemine whether; the information provided was clear in the description of the event and
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identification of safety significance; the event cause was identified and corrective actions taken (or planned) were appropriate; the report satis-fied requirements with respect to infonnation provided and timeliness of submittal per NUREG 0161 and Technical Specification 6.7 criteria. Those reports annotated with an asterisk (*) concern events that required inspector followup action and inspector review / evaluation of the event is documented elsewhere, in this or other inspection reportc.
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- LER 81-25, Containment Isolation Valve LRW-95 failed to close per Technical Specification 4.7.D.1 during quarterly surveillance testing due to mechanical binding of the valve stem. Event date September 28,-
1981, report date October 21, 1981.
It is noted that this valve is the subject of LER 81-17, discussed in detail 13. of IR 50-271/81-13. Licensee actions in regard to this failure will be the subject of further inspector review.
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LER 81-26, Surveillance testing interval for functional test of the ATWS/RPT System was exceeded for four days. Event date October 5, 1981, report date November 3, 1981.
-14.
Review of NUREG 0737 - TMI Action Plan Requirements ermont Yankee implementation of certain NUREG 0737 - TMI Action Plan v
requirements was reviewed to determine the status of NUREG items with a due date of January 1, 1982, and to verify actions have been completed for those NUREG items with a specified completion date of October 1,1981.
The review consisted of establishing a licensee coninitment to fulfill a NUREG 0737 requirement and a followup inspection to determine the status of implementation. References used for this review are listed below.
(i) NUREG 0737, Clarification of TMI Action Plan Requirements, October 31, 1980 (ii) NRC (Denton) Letter to All Operating Nuclear Power Plants, October 30, 1979
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(iii)
NRC (Denton) Letter to All PowerReactor Applicants and Licensees, March 28, 1980 (iv)
VY Letter WY 80-1/0, Post TMI Requirements - Implementation Date Commitments, December 15, 1980 (v)
VY Letter WY 80-145, TAP Item II.K 3,27, October 10,1980 (vi)
VY Letter WY 80-166, Proposed Technical Specification Change No. 93, December 1, 1980 (vii)
VY Letter FVY 81-69, TAP Item II.K.3.27, April 17, 1981 (viii)
NRC Letter to R. L. Smith, TAP Item II.K,3,27, June 30,1981 (ix)
NRC Letter to R. L. Smith, TAP Item II.K.3.22, September 1,1981 (x)
VY Letter WY 80-175, TAP Item II.K.3.13, December 30, 1980 (xi)
VY Letter FVY 81-111, TAP Item II.K.3 I5, August 5, 1981 (xii)
NRC Letter to R. L. Smith, NRC Staff Evaluation of TMI-2 Category A Items, April 11, 1980 (xiii)
NRC Letter to R. L. Smith, Confimatory Order for TMI Related Requirements, July 10, 1981 (xiv)
VY Letter FVY 81-110, Response to Confimatory Order dated July 10, 1918 and August 5, 1981 In the listings that follow, " Item Numbers" refer to the NUREG 0737 requirements.
a.
Item II.E.4.2.5B Modifications for Containment Isolation Pressure Setpoint (1)_ Requirements: References (1)and(ii)
The containment setpoint pressure that initiates containment isolation for nonessential penetrations must be reduced to the minimum compatible with normal operating conditions; that is, within one (1) psi.
(2) Licensee Commitments:
Reference (iv)
The plant currently operates with a margin less than 1 asi between the nomal containment operating pressure and tie pressure setpoint which initiates containment isolation. No additional action on this item (setpoint changes) will be taken,
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(3)
Inspection Findings The pressure setpoint that initiates containment isolation is set in accordance with the Technical Specifications, to less than or equal to 2.5 psig. - The normal containment operating pressure is 1.9 psig, or less than 1 psi below the trip setpoint.
The inspector had no further questions on this item.
b.
Item II.E.4.2.7 Containment Isolation on High Radiation Signal (1) Requirements: Reference (i) and (ii)
Containment purge and vent isolation valves must close on a high radiation signal to enhance containment isolation
dependability.
(2) Licensee Comitments:
Reference (iv)
Containment purge and vent valves, as tested in Technical Specification Table 4.7.2.a. automatically close as a re-sult of three isolation signals, one of them being high radiation in the reactor building exhaust plenum or refuel 1ng floor. Since this isolation signal is already identified in the Technical Specifications, no further action is necessary.
(3)
Inspection Findings Seventeen (17) containment purge and vent valves, as listed in Technical Specification Table 4.7.2.a automatically close upon receipt of a signal for reactor low-low water level, high drywell pressure and/or high radiation level from either the refueling area zone or the reactor building ventilation exhaust plenum radiation monitors. Any of the above signals results in a group 3 isolation for the seventeen valves, which are located in piping lines varying in size from 3/4 inch to 18 inches in diameter. Valve locations and isolation logic were verified by review of plant drawings G191175, G191238, VY E-75-002-3 and G191301, Sheets 1100-1120. The isolation logic was found to be as described by Reference (iv).
The inspector noted that the refuel zore radiation monitors are located on the 345 foot elevation of the recctor building l
and are thus remote from a source tem in the drywell.
Additionally, the reactor building ventilation exhaust moni-tors arc located in the reactor building above the 280 foot I
elevation, mounted on the sides of the reactor building exhaust
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vent header and about five (5) feet above the 1A Standby
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GasTreatmentTrain(SGT).
The licensee stated that the current operating practice that uses the SGT system as a torus vent path to maintain drywell-torus differential pressure, along with the vent header radiation monitor proximity to the SGT system, will result in the desired isolation. The inspector acknowledged the above.
The inspector noted, however, that future changes in the torus ventilation path, necessitated by operation with the drywell inerted, may eliminate the viability of using the RB ventilation exhaust monitors to initiate purge and vent valve isolation from a source term inside the drywell. This item will be re-examined on a subsequent inspection pending a detemination of the long term configuration of plant ventilation systems under inerted conditions, c.
II.E.4.1.2 Install Dedicated Penetration for Hydrcgen Recombiners (1) Requirements:
References (1), (ii) and (xii)
Plants using external recombiner or purge systems for post accident combustible gas control should provide, by July 1,1981, containment penetration systems for external recombiner or purge systems that are dedicated to that service only; that are single failure proof for containment isolation purposes and single failure proof for operation; that are sized such that the flow requirements are satisfied; and, that are safety grade. Con-tainment Atmosphere Dilution (CAD) systems are considered to be purge systems.
(2) Licensee Commitments: Reference (iv)
Vermont Yankee has a CAD system. The intent of the hUREG 0737 clarification for this item is met in that existing connections on the CAD system are single failure proof for containment isolation purposes and single failure proof for operation. By letter dated April 11, 1980 (Reference xii),theNRCStaff stated that pending resolution of the post-accident combustible gas control (inerting) issue, the TMI Short Tem 1.essons i. earned requirements had been satisfied.
(3)
Inspection Findings The inspector noted by review of drawing VY-E-75-002-3 and examination of installed equipment that the CAD system is single failure proof for operation and containment isolation
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purposes. The system consists of injection, vent and sampling subsystems, which uses dedicated penetrations for the sample subsystems and combined penetrations for the injection arid vent subsp tems. The subsystems are redundant and designed to Quality Group B and Seismic Category I criteria in accordance with the requirements for an engineered safety features system.
The penetrations servicing the CAD system are adequately sized for CAD system flow requirements.
The inspector noted during discussions with the licensee that they were aware of additional requirements contained in SECY-80-399, published October 2, 1980, which would require Vermont Yankee to have the capability to install hydrogen recombiners. The licensee stated that the comitments made in Reference (iv) apply to requirements applicable to the CAD system only. Further consideration of penetration design requirements necessary to support recombiner operation would be addressed when NRC requirements were formalized. The inspector acknowledged the above.
The inspector had no further coments on this item at the present. Licensee actions to meet existing requirements are considered complete. However, this item will be examined on a subsequent inspection to determine what additional actions may be required pending issuance of the Degraded Core cooling rule, d.
II.K.3.27 Common Reference for Vessel Water Level (1) Requirements: References (i), (ii), (viii) and (xiii)
All vessel level instruments should be referenced to the same point; either the bottom of the vessel or the top of the active fuel. Revised Technical Specifications are required to reflect the changes in level reference. The requirements should be im-plemented by Jul3 1, 1981.
(2) Licensee Comitments:
References (iv),(v),(vi)and(xiv)
Changes will be made to level instrumentation to meet this requirement by replacing the scales on the RPS/ECCS and feed-water control indicators and recorders so that the level re-ferred to by each device will be relative to the top of the enriched fuel. Additionally, extensive procedure revision, operator retraining and proposed Technical Specification changes would be completed by the 1981 refueling outag.
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The delay in implementation of the requirements beyond July 1, 1981, was requested to provide the best opportunity (during a scheduledoutage)tuprovidecomprehensiveretrainingof operations personnel prior to use of new procedures.
(3)
Inspection Findings Proposed Technical Specification changes were submitted by Reference (vi)onDecember1,1980. The deferred implementa-tion of this item was implicitly approved in Reference (viii)
and made contingent upon NRC Staff approval of the proposed Technical Specifications.
Level indications from the Shutdown Recorder (CRP 9-5), the Refuel Indicator (CRP 9-4) and the Wide Range Yarways (CRP 9-3)
are already referenced to the top of the active fuel. The licensee plans to make scale changes cn the Yarway/ARI indica-tors (CRP 9-5 and 25-5, 25-6 racks) and the GEMAC indicators (CRP9-5and25-5,25-6 racks)to provide the same reference point. Specifically, the Yarway/ARI indicators will be re-scaled to a range of 77 inches to 177 inches; the GEMACS will be rescaled to a range of 127 inches to 187 inches. The scale changes will be made during the 1981 refueling outage, which is scheduled to end by December 1,1981.
The inspector had no further coment on this item at the present.
This item will be re-examined on a subsequent inspection.
e.
II.K.3.13.B Modifications for RCIC Initiation Level (1) Requirements: Reference (i)
The initiation level of the RCIC system should be changed so that the RCIC system initiates at a higher level than the HPCI system. The initiation logic of the RCIC system should be modified so that the RCIC system will restart on low water level. Analyses should be perfonned to evaluate these changes and submitted to the NRC Staff; changes should be implemented by July 1,1981, if justified by the analyses.
(2) Licensee Commitments:
References (iv)and(x)
By letter dated October 1, 1980, to D. G. Eisenhut (NRC), a report was forwarded which presented VY's' analysis, conclusions and recomendations regarding the separation of RCIC and HPCI initiation levels. The analysis concluded that separating the
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initiation setpoints would provide negligible benefits and as such, no changes to the RCIC setpoint will be made.
The RCIC logic will be modified to allow RCIC restart on low water level without reliance on a manual reset at the turbine. The modification will be made during the first outage of sufficient duration.
(3) Inspection Findings Modifications to the RCIC logic to allow restart on low water level are currently scheduled to be completed during the 1981 refueling cutage in accordance with PDCR 80-05, RCIC Auto Restart and Remote Reset. A limitorgue motor operator will be installed on the RCIC turbine trip / throttle valve to allow the valve to be reset automatically following a trip on vessel high level. The linkage arrangement on the trip / throttle valve will be changed to allow the valve to be reset without oil pressure.
The high water level trip signal will be removed from the trip / throttle valve and instead close the upstream steam stop valve, V13-131. Closure of V13-131 will shutdown the
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turbine and trip the trip / throttle valve on low oil pressure.
A logic change will also be made such that high water level and V13-131 closure will automatically reset the trip / throttle valve to make the system ready to restart on low water level.
The inspector had no further comments on this item for the present. This item will be re-examined on a subsequent inspection pending completion of the PDCR 80-05 modifications.
f.
II.K.3.15 HPCI/RCIC Break Detection Logic Modifications (1) Requirements: References (i) and (ix)
Modify the pipe break detection circuitry on the HPCI and RCIC systems to eliminate spurious isolation during system startup.
Complete modifications by July 1, 1981.
(2) Licensee Cotmitments:
References (iv)and(xi)
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A design change will be installed on the RCIC/HFCI isolation logic to minimize inadvertent isolations during system initiation.
The modifications will be completed during the first outage of sufficient duration to complete the work following receipt of material.
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(3) Inspection Findings Work was completed during the shutdown for the 1981 refueling, outage to modify the HPCI system. Work was completed under PDCR 81-03, HPCI Start Modifications. The HPCI governor valve centrol system was modified such that the governor valve will be partially shut during steam admission. This will serve to reduce steam flow during startup and eliminate the high differential pressure which could cause an inadvertent isolation.
Modifications to the RCIC system are scheduled for completion during the 1981 refueling outage under EDCR 80-54, RCIC Steam Line Isolation Modifications. A time delay will be installed in the break detection logic that will ensure the system is isolated only if a high differential pressure is sensed for a long enough time to indicate that the differential pressure is not the result of the system starting transient.
The inspector had no further questions on this item for the present. This item will be re-examined on a subsequent inspection pending completion of all modifications and associated system operability testing, g.
II.B.4.2A/2B Training for Mitigating Core Damage (1) Requirements: References (i) and (iii)
A training program shall be developed and implemented by April 1, 1981, to teach the use of installed equipment and systems to control or mitigate accidents in which the core is severely damaged. Shift Technical Advisors and operating personnel from the plant manager through the operations chain to licensed operators shall receive all training in Enclosure 3 to the Denton March 28, 1980, letter. Managers in the Instrument and Control, Chemistry and Health Physics Departments shall receive training commensurate with their respen! bil'. ties. The initial training programs should be i
completed by Octeter 1,1981.
(2) Licensee Commitments: Reference (ix)
Training for mitigating core damage in accordance with the March 28, 1980, Denton letter was incorporated into the licensed requalification program submitted on July 29, 1980.
Training in this area will be added to the STA program. Train-ing of the plant managers may not meet the requirements of the NUREG clarification. All plant personnel will receive training in emergency procedures commensurate with their responsibilities in these procedure s
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(3)
Inspection Findings-The Vermont Yankee initial licensed and operator requalification training programs were modified to include training on mitigating core damage, as noted by a review of AP 0711 dated July 24, 1981, AP 0710 dated July 24, 1981, and the 1981-1982 R0 Hot Licensed Program schedule of lecture topics. Training in degraded core cooling had also been included in the 1980-1981 Hot Licensed Program. Additionally, augmented training in this subject area
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was given to various plant personnel over the period from
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May 4, 1981 to July 23, 1981. The augmented training was
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based on NDEO-24708 and the GE Program Course on mitigating
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core damage - M+NT Engineering Training, Volume 1, Degraded Core. Supplemental Topics included a presentation on the new Emergency Procedure Guidelines.
Based on a review of attendance records, the inspector deter-mined that the following plant personnel received the subject training:
Plant Manager, Assistant Plant Manager, Operations Superintendent, Technical Services Superintendent, Nuclear Safety Engineers (STAS), Senior Reactor Operators, Reactor Operators and Operations Training Department Staff. The inspector noted from the attendance sheets that one reactor operator attended only one day of two-day lecture series. This was confirmed through an interview with the individual. Train-ing Department personnel stated that failure of the individual-to attend both classes was apparently an oversight. The individual was subsequently scheduled to make-up the missed-training.
The inspector noted that the individual received an R0 license in the Spring of 1981 and received Degraded Core Training as part of the Initial Hot License Program.
Training received by the personnel listed above includes managers with responsibilities over the Instrument and Control and Chemistry and Health Physics Departments. However, no technicians or managers below the Superintendent level in the subject departments received the training. The Plant Manager stated that personnel below the Superintendent level were not required to attend the lectures in that the training subject mattef (mitigating core damage) fell outside the scope of their responsibilities for response to an accident.
The inspector reviewed lesson plans and lecture presentation material 1from the course.
Presentation topics were compared with these listed in Enclosure 3 to the March 28, 1980, Denton letter and were found to cover the suggested subject matter, as applicable to a BWR.
The inspector had no further comment on this item.
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15.
APRM Inputs to Rod Block Circuits The inspector received infomation from the NRC Staff that indicated a potential problem had been identified at other BWR sites involving Average Power Range Monitor (APRM) inputs to the Rod Block Circuit in the Reactor Manual Control System (RMCS). The APRM inputs to the P,MCS were grouped different than the APRM inputs to the RPS, such that the CRP 9-5 bypass switches could remove up to two APRM inputs per trip system. Technical Specification Table 3.2.5 requires a minimum of 2 instrument channels per trip system be operable. The above infomation was discussed with the licensee. A review will be conducted to determine whether the problem a) plies to Vermont Yankee. This item is unresolved pending completion of tie review and subsequent inspection by the NRC (UNR 50-271/81-18-02).
16.
Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable items, items of noncompliance, or deviations. Unresolved items are discussed in Details 12.a. and 15 of this report, 17.
Management Meetings During the period of the inspection, licensee management was periodically notified of the preliminary findings by the resident inspectors. A summary was also provided at the conclusion of the inspection and prior to report issuance. Additionally, the resident inspectors attended the entrance and exit interviews on October 5, 1981 and October 8, 1981, respectively, conducted by a region-based inspector in regard to an inspection of the licensee's preparations for Cycle 9 reload.
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