IR 05000271/1989001
| ML20247A085 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 03/19/1989 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20247A035 | List: |
| References | |
| 50-271-89-01, 50-271-89-1, IEB-85-003, IEB-85-3, NUDOCS 8903290040 | |
| Download: ML20247A085 (64) | |
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U.S. NUCLEAR REGULATORY COMMISSION Region I Report No.:
50-271/89-01 l
l Docket No.:
50-271 License No.:
Licensee:
Vermont Yankee Nuclear Power Corporation-l RD 5, Box 169
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'Brattleboro, Vermont 05301 i
Facility:
Vermont Yankee Nuclear Power Station Inspection At: Vernon, Vermont
Inspection Conducted: January 4 - February 13, 1989 Inspectors:
Geoffrey E. Grant, Senior Resident Inspector Joh B. Macdonald, Resident Inspector Approved by:
- Ie( / mb 3'$~d'
Donald R. Haverkamp, Chief (/ ~
Date Reactor Projects Section No. 3C Inspection Summary:
Inspection on January 4 - February.13, 1989 (Report No. 50-271/89-01)
Areas Inspected: Routine-inspection on daytime and backshifts by two resident inspectors of:
actions on. previous inspection findings;. operational safety;
-security; plant operations; maintenance and surveillance;. engineering support; radiological controls;. licensee event reports; licensee response to NRC initi-
'atives; and, periodic reports.
Results:
1.
General Conclusions on Adequacy, Strength or Weakness in Licensee Programs The licensee implementation of technical specification (TS) 6.2.A.6 requirements which define overall plant operations review comniittee (PORC)
responsibilities is weak in some areas.
The licensee prograu to ensure PORC review of plant operations in order to detect any potential safety hazards is poorly defined. This report details an instance of the initial lack of PORC involvement or review of an unanalyzed operational condition (Section 10.1).
Lack of good performance in this area primarily ' stems from insufficient program definition.
The plant procedure that governs PORC activities merely mimics the TS 6.2. A.6 defined responsibilities without providing adequate implementation guidance. Greater PORC involve-ment in the review of plant operations is required.
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i-InspectioniSummary (Continued)
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Violations The.= licensee identified a violation of a TS requirement to follow approved procedures'when a radiation department technician isolated the containment.
air : monitor. while ' performing a walkthrough of an unapproved procedure revision. The licensee' took prompt corrective action upon identification
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of the-problem.
No Notice of Violation is being issued. (Section 8.1).
3.
Unresolved Items Three unresolved items were identified during 'this inspection period:
l Review of ' the permanent repair and post-installation test for the
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reactor building railroad access doors (Section 10.1)
Review of licensee corrective actions to. ensure that PORC fulfills-
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all required responsibilities (Section 10.1).
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Review of the final resolution of what constitutes the design basis for the reactor building-to-torus vacuum breakers -(Section 10.2).
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TABLE OF CONTENTS Page 1.
Persons Contacted.........................................
2.
S umma ry o f Fa c i l i ty Acti v i ti e s............................
3.
Status of Previous Inspection Findings (IP 92701, 92702*).................................................
3.1 (Closed) Unresolved Item 87-06-02 - Review Spent Fuel Pool Rack Replacement Under 10 CFR 50.59......
3.2 (Closed) Violation 87-16-02 - Release of Radioactive Material from the RCA..................
3.3 (Closed) Unresolved Item 86-22-02 - Review Licensee Actions with Respect to GE SIL 457 Scram Valve Diaphrams..............................
3.4 (Closed) Unresolved Item 86-10-02 - Review Licensee Short and Long Term Corrective Actions with Respect to the Condensate Storage Tank (CST) Corrosion Problem............................
3.5 (Update) Unresolved Item 88-14-02 - Fire Protection Program Weaknesses......................
4.
Operational Safety (IP 71707,71710)......................
4.1 Plant Operations Review..............................
4.2 Safety System Review.................................
4.3 Feedwater Leak Detection System Status...............
4.4 Inoperable Equipment.................................
4.5 Review of Lifted Leads, Jumpers and Mechanical Bypasses...........................................
4.6 Review of Switching and Tagging Operations...........
4.7 Operational Safety Findi ng s.........................
1 5.
Security (IP 71707).......................................
i 5.1 Observations of Physical Security....................
6.
Plant Operations (IP 71707,93702,82201).................
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6.1 Notification of Unusual Event - January 4,1989......
i 6.2 Notification of Unusual Event - February 2,1989.....
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L e, TableofContents-(Continued)
Page 7.
Maintenance / Surveillance (IP 71710,-61726,62703).........
.7.1 -Valve CS-12A Inoperability...........................
7.2 UPS-1A Inoperability.................................
7.3 UPS-1B Inoperability.................................
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Radiological Control s (IP 71707).........................
8.1 - Containment Ai r Monitor Isolation....................
9.
Licensee Event. Reporti ng ' ( LER) (IP 93702).................
9.1 LER 88-15............................................
9.2 LER 89-01............................................
9.3 LER 89-02............................................
l10. ~ Engineering Support (71707, 35502, 37828).................
12-10.1 Potential Degradation of Secondary Containment Integrity...........................................
10.2. Reactor Building-to-Torus Vacuum Breaker Design......
10.3 Fire Protection System Material Issue Deficiencies...
11.
Review of Licensee Response to NRC Initiatives (IP35502)..............................................
11.1 Review of NUREG-0737 Commitments.....................
11.2 IE Bulletin 85-03....................................
12.
Review of Periodic and Special Reports (IP 71707).........
13. Management Meetings (IP 30703)............................
13.1 Licensee Requested Management Meeting................
Attachment A:
Reactor Building Access Door Modification Attachment B: Meeting Notice Attachment C: Attendee List Attachment D: Meeting Material Enclosure
- The NRC Inspection Manual inspection procedure (IP) that was used as inspection guidance is listed for each applicable report section.
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DETAILS
- 1.
Persons Contacted Interviews'
and ' discussions were conducted. with members of the licensee staff and management during the report period to obtain.informa-
. tion pertinent to the areas inspected.. Inspection findings were discussed periodically with the ' management and supervisory personnel listed below.
y Mr. P. Donnelly, Maintenance Superintendent
- Mr. R. Grippardi, Quality Assurance Supervisor
- Mr. S. Jefferson, Assistant to Plant Superintendent Mr. J. Herron, Operations Supervisor
.Mr R. Lopriore,. Maintenance Supervisor
- Mr. R. Pagodin, Technical Services Superintendent
- Mr. J..Pelletier, Plant Manager
- Mr. D. Porter,. Shift Supervisor
- Mr. R. Wanczyk,' Operations Superintendent Mr. T. Watson, I & C Supervisor
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- Attendee at~ post-inspection exit meeting conducted on March 7, 1989.
l 2.
Summary of Facility Activities Vermont ~ Yankee Nuclear Power Station (VYNPS.or the licensee) continued power coastdown operations until February 10, 1989, when a plant shutdown was commenced to begin a refueling and maintenance outage.. Power was approximately 81% of rated power at commencement of the shutdown.
The turbine was removed from the grid at 9:45 p.m.
on February 10, and the reactor was shutdown at 1:06 a.m.
on February 11.
During coas tdown,
scheduled power reductions were conducted to perform routine surveil-lances.
An Unusual Event (UE) was declared on January 4 when a plant
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shutdown was commenced due to an "A" uninterruptible power supply (UPS)
failure while the
"A" core spray (CS) loop was out of service for repairs to valve CS-12A-. (see section 6.1).
An unanalyzed condition relating to the reactor building railroad access doors was reported to the NRC on January 4 (see Section 10.1). An Unusual Event was declared on February 2 when an unplanned loss of the startup transformers occurred (see Section 6.2).
Mr. John Herron assumed the duties of Operations Supervisor on January 16, 1989.
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Status of Previous Inspection Findings
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3.1 (Closed) Unresolved Item 87-06-02:
Review Spent Fuel pool Rack Replacement Under 10 CFR 50.59.
In March of 1987 the licensee con-cluded that the spent fuel pool (SFP) rack replacement did not create an unreviewed safety question, as defined by 10 CFR 50.59, and, therefore, could be performed without requesting authorization of the NRC. However, following review of this position, the NRC determined that a TS amendment - was required to authorize SFP reracking.
On April 25, 1986, the licensee submitted Proposed Change 133. -On May 20, 1988, the Commission issued Amendment - No. 104 to the VYNPS Operating License which authorizes the installation of new racks designed to accommodate 2870 fuel a s serr.bli es.
The amendment main-tained the existing TS limit of not more than 2000 assemblies. The inspector had no further questions.
3.2 (Closed) Violation 87-16-02:
Release of Radioactive Material from the RCA. On September 28, 1987, the licensee discovered radioactive material outside the radiation controlled area (RCA) but within the protected area.
During a routine survey of a trash dumpster, a radiation protection technician identified a bag containing dirt that read 500 CPM on an' RM-14.
Although no regulatory limits were exceeded, a Notice of Violation (NOV) was issued because this inci-dent was similar to previous losses of control of low level radio-active material.
The inspectors reviewed the licensee response to the NOV, dated March 25, 1988, and ensured that the corrective actions described were sufficient to preclude recurrence of a similar event.
Further, no other radioactive material control concerns of violations have been identified during subsequent routine resident inspections.
In addition, recent quality assurance (QA). audits were reviewed with respect to this issue and no adverse findings were identified during the audits.
The inspectors had no further questions.
3.3 (Closed) Unresolved Item 86-22-02:
Review Licensee Actions with Respect to GE SIL 457, Scram Valve Diaphragms. On September 28, 1987, GE issued SIL 457 to inform licensees of instances of premature scram valve diaphragm failures. The licensee evaluated the SIL recommended actions and tested scram valve diaphragms including some which were from stock and some which were removed from service. The conclusion of the test report was that the diaphragms have a conservative installed life of twenty years which is several years longer than the life of most of the scram valve diaphragms currently installed. The licensee ordered and received in stock 189 diaphragms of which approximately one-third to one-half are scheduled to be installed during the upcoming 1989 refueling outage.
Following inspection and testing of the replaced diaphragms, the licensee will determine the appropriate course of action with respect to the remaining in place diaphragms. The inspectors will follow the diaphragm replacement and had no further questions.
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3.4 (Closed) Unresolved Item 86-10-02:
Review Licensee Short and Long Term Corrective Actions with Respect to the Condensate Storage Tank (CST) Corrosion Problem.
In March 1986, the licensee identified two through-floor leaks in the CST.
The two holes were approximately 3/16 inches each in diameter and were located in the southwest quad-rant of the tank approximately one foot from the tank wall.
The licensee performed UT examinations of approximately 41% of the floor area and identified three major areas and one small area of signifi-cant wall thinning.
A wall thinning of greater than 0.100 inches from the nominal 0.340 inches was defined as significant. The 11cen-see welded aluminum 3/8 inch patch plates over the degraded areas.
The exterior tank wall-to-concrete interface was sealed with a leak proof membrane material and the tank insulation was replaced.
The Operations Department performs a weekly CST leak monitoring surveil-lance.
No indications of leakage have been observed.
Periodic UT examinations have indicated no further floor wall thinning beyond minimum wall thickness.
The next UT examination is scheduled for refueling outage during the Spring of 1989. The resident inspectors will continue to monitor this program and have nc further questions at this time. The licensee's root cause determination and UT exam-inations are being tracked under unresolved item 50-271/86-13-01.
3.5 (Update) Unresolved Item 88-14-02:
Fire Protection Program Weak-nesses.
Material issue deficiencies identified in Section 10.3 of this report will be added to this unresolved item.
4.
Operational Safety 4.1 Plant Operations Review The inspector observed plant operations during regular and backshift teurs of the following areas:
Control Room Cable Vault Reactor Building Fence Line (Protected Area)
Diesel Generator Rooms Intake Structure Vital Switchgear Room Turbine Building Control room instruments were observed for correlation between channels, proper functioning, and conformance with technical specifi-cations. Alarm conditions in effect and alarms received in the con-trol room were reviewed and discussed with the operators. Operator awareness and response to these conditions were reviewed. Operators were found cognizant of board and plant conditions. Control room and shift manning were compered with technical specification require-ments.
Posting and control of radiation, contaminated and high radiation areas were inspected. Use of and compliance with radiation
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work : permits and use of required personnel monitoring devices were checked. Plant housekeeping controls were observed including. control of flammable and other hazardous materials. During plant tours,' logs and records were reviewed to ensure compliance with station proced-ures, to determine if entries were correctly made,. and to verify
. correct communication of equipment status.
These records included various operating logs, turnover sheets, tagout and jumper logs, and potential reportable occurrence reports.
Inspections of.the control room.were performed on weekends and backshifts including January 4-6,.
9-13, 18-20, 30, 31 and February 1-3, 1989. " Deep backshift" inspec-tions were conducted from 9:00 p.m.,
February 10, until 5:00 a.m.,
February 11, 1989, during the plant shutdown to begin a refueling and maintenance outage.
Operators and shift supervisors were alert, attentive and responded appropriately to annunciators and~ plant conditions.
4.2 Safety System Review
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The emergency diesel generators, reactor core isolation cooling, core spray, residual heat removal, standby gas treatment, residual heat removal service water, safety related electrical, and high pressure coolant injection systems were reviewed to verify. proper alignment and operational status in the standby mode.
The review included verification that:
(i) accessible major flow path valves were cor-rectly positioned; (ii) power supplies were energized; (iii) lubri-cation. and component cooling was proper; and (iv) components were operable based on a visual inspection of equipment for leakage and general conditions.
No violations ur safety concerns were identified.
4.3 Feedwater Leak Detection System Status The inspector reviewed the feedwater leakage detection system and the monthly performance summary provided by the licensee in accordance with VYNPC letter FVY 82-105.
The licensee reported that, based on the leakage monitoring data for January 1989, there were no devia-J tions in excess of 0.10 from the steady state value of normalized thermocouple readings with the exception of January 4 when a decrease in feedwater nozzle temperatures occurred as a result of a partial plant shutdown. Temperatures subsequently returned to normal.
4.4 Inoperable Equipment Actions taken by plant personnel during periods when equipment was inoperable were rsviewed to verify that:
technical specification I
l limits were met; alternate surveillance testing was completed satis-i-
factorily; and, equipment return to service upon completion of l
repairs was proper.
This review was completed for the following I
items:
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January 4 -- Core spray (CS) loop "A" due to failure of CS-12A.
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Refer to Sections'6.1 and 7.1.
January 4 -- Low pressure coolant injection (LPCI) loop "A" due
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to failure of the uninterruptible power supply UPS-1A. Refer to Sections 6.1 and 7.2.
January 4 -- toxic gas monitor.
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January 8 -
"A" emergency core cooling system (ECSS) 24 volt
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battery charger.
January 9 -- toxic gas monitor.
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"B" LPCI due to UPS-1B failure. Refer to Section
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7.3.
January 20 Reactor building-to-torus vacuum breakers (as
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containment isolation valves).
Refer to Section 10.2.
January 21 -- toxic gas monitor.
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January 30 -- standby gas treatment (SGT) system "A".
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February 2 -- startup transformers.
Refer to Section 6.2.
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February 5 -- toxic gas monitor.
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4.5 Review of Lifted Leads, Jumpers and Mechanical Bypasses Lifted lead and jumper (LL/J) requests and mechanical bypasses (MB)
were reviewed to verify that controls established by AP 0020 were met, no conflict with the technical specifications were created, the requests were properly approved prior to installation, and a safety evaluation in accordance with 10 CFR 50.59 was prepared if required.
Implementation of the requests was reviewed on a sampling basis. The l
following requests were reviewed:
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i LL/J 89-0003 implemented January 19 for the battery room exhaust
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fan.
LL/J 89-0012 implemented February 11 for control rod (CR) 22-11
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full-in signal.
LL/J 89-0014 implemented February 12 for removal of the main
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steam line high radiation drawers.
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4.6 Review of Switching and Tagging Operations The switching and tagging log was reviewed and tagging activities were inspected to verify plant equipment was controlled in accordance with the requirements of AP 0140, Vermont Local Control Switching Rules. Switching and tagging orders were reviewed for the majority of inoperable equipment repairs identified in Section 4.4.
4.7 Operational Safety Findings Both the toxic gas monitor system and the uninterruptible power. sup-plies continue to exhibit reduced reliability.
Licensee administra-tive control of off-normal system configurations by the use of LL/J, mechanical bypass, and switching and tagging procedures, as reviewed in Sections 4.5 and 4.6, was in compliance with procedural instruc-tions and was consistent with plant safety.
Backshift inspections have consistently found operators to be alert and attentive. Opera-tions are routinely conducted in a professional manner in an atmos-phere of quiet control and competence.
With the exception of iso-lated instances, overall plant cleanliness and material condition continue to be good.
No deficiencies were identified in licensee operations associated with the reviews covered in Section 4.
5.
Security 5.1 Observations of Physical Security Selected aspects of plant physical security were reviewed during regular and backshift hours to verify that controls were in accord-ance with the security plan and approved procedures.
This review included the following security measures: guard staffing; vital and protected area barrier integrity; maintenance of isolation zones, and, implementation of access controls, including authorization, badging, escorting, and searches.
No inadequacies were identified.
6.
Plant Operations 6.1 Notification of Unusual Event - January 4, 1989 On January 4,1989, at 12:20 p.m.,
while operating at 90% of rated power, the "A" core spray (CS) loop was declared inoperable in order to perform maintenance on the CS-12A valve (loop injection valve).
During previous monthly surveillance of the CS system, abnormal valve operator noise was noted during cycling of CS-12A.
Required alter-nate testing of safety systems was accomplished prior to removing the
"A" CS loop from service. At 6:10 p.m. on January 4, uninterruptible
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power supply UPS-1A was declared inoperable due to a blown inverter leg fuse.
The UPS is a subsystem of the low pressure coolant injec-tion (LPCI) system, which provides power to the LPCI injection valves.
Failure of UPS-1A caused the "A" LPCI loop to be declared inoperable.
A reactor shutdown was commenced in accordance with technical specification (TS) 3.5. A.6 which requires that an orderly shutdown be initiated and cold shutdown conditions met within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if alternate testing criteria are not met.
The licensee declared an Unusual Event (UE) at 5:10 p.m.
on January 4, in accordance with facility emergency action levels (EALs)
procedure AP 3125, " Emergency Plan Classification and Action Level Schemes". Procedure AP 3125 requires that a UE be declared when the loss of a system function or engineered safety feature requires a plant shutdown in accordance with plant TSs.
The NRC Operations Center and appropriate state and local notifications were made. The reactor ' shutdown and UE were terminated at 3:05 a.m.
on January 5 when UPS-1A was - repaired, post-maintenance testing completed, and declared operable.
Reactor power had been reduced to approximately 79% of rated power.
Reactor power was subsequently returned to 90%
of rated power (full power for current coastdown conditions).
Valve CS-12A was repaired and the
"A" CS loop returned to service on January 5.
Details on the failures and repairs of CS-12A and UPS-1A are documented in Sections 7.1 and 7.2, respectively.
Licensee personnel responded appropriately to this event. The condi-tion was identified and classified in a timely manner.
Implementa-tion of various aspects of the licensee emergency response plan was appropriate and well coordinated. No deficiencies were noted in the licensee response to this event.
6.2 notification of Unusual Event-February 2, 1989 On February 2 at 1:17 p.m., while the plant was operating at 83%
rated power, plant operators reported smoke in the area of the bus SA cubicle. This cubicle is located outside the west wall of the tur-bine building and adjacent to the startup transformers.
Bus 5A sup-plies non-safety 4160V power to non-vital auxiliary loads such as cooling tower fans and circulating water booster pumps.
This equip-ment was not in service when smoke was reported as the plant was in open cycle operation. The fire brigade was immediately dispatched to the scene and reported the smell of acrid smoke but observed no fire.
In order to troubleshoot the fault, at 1:30 p.m. the shift supervisor directed the opening of switchyard breaker T-3 which de-energized power to the start-up transformers and the SA and 5B busses.
Smoke in the area of the Bus SA cubicle began to dissipate.
Per facility emergency action level procedures, the unplanned loss of both start-l up transformers resulted in the declaration of an Unusual Event at l
1:50 p.m.
State and local authorities were notified at 2:05 p.m. and the NRC Operations Center was notified at 2:10 p.m.
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In. response to this event, the resident inspectors went to the con-trol ' room and established continuous. ENS communications with the Region'I incident response center which was partially activated. The-on-site resident staff. was augmented by the backup site- (Yankee Nuclear Power _ Station in Rowe, Massachusetts) senior resident inspec-tor. Licensee troubleshooting determined that the cause of the smoke-in the cubicle.was a faulted potential transformer which normally'
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provides over-voltage indication for bus SA.
The licensee isolated the. fault':from-the start-up transformers and at 6:44~p.m. on February. 2, the T-3 breaker was closed and.the start-up transformers were re-energized.
The licensee secured from the Unusual Event at 7i20 p.m.
Bus SA remained de-energized pending. replacement of the -
potential transformer.
.The licensee responded appropriately, and accurately identified and classified the Unusual Event. On shift personnel performed in a' con-trolled and professional manner ins response to the event and during communications with.the NRC. Tne inspectors had no further questions
.concerning this event.
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7.
Maintenance / Surveillance 7.1 Valve CS-12A Inoperability On January 4,1989, at 12:20 p.m., the "A" core spray (CS) loop was declared inoperable when injection valve CS-12A was removed from ser-vice in order to troubleshoot the cause of observed noisy operation.
The CS-12A valve actuator (Limitorque SMB-2) was removed and trans-ported to the maintenance shop for inspection and repairs. Mainten-ance activities were performed within the scope of MR 89-0008.
A visual inspection of the actuator internal components revealed no -
anomalous conditions, with the exception of a low grease content.
Following bench cycling of the actuator, the abnormal noises were isolated to the actuator motor brake unit (Ding Dynamic Brake). The i
brake unit was cleaned.:nd adjusted, but noisy operations continued.
l In order to minimize system unavailability, a new motor and brake l
unit. were procured from existing stores and were installed on the l-actuator.
The valve and actuator were re-assembled.
On January 5, l-post-maintenance and operability testing of CS-12A was satisfactorily completed and the "A" core spray loop was declared operable.
Maintenance department root cause analysis of the replaced motor identified a degraded brake coil which when energized had insuffic-ient capacity to fully disengage the brake mechanism. The resultant brake contact caused the abnormal operational noises.
The prelim-inary failure mechanism for the degraded brake coil was determined by the licensee to be end-of-service lif _ _ _ - _
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The licensee responded conservatively to the abnormal operational condition of CS-12A.
Inspection and _ troubleshooting activities were logical'and deliberate. Appropriate efforts were taken to return the valve to service expeditiously.and minimize system unavailability.
It was noted that on December 7,1988, the CS-12A and CS-12B valves were observed to have loose motor brake cover bolts. The loose bolts were identified during MOV walkdowns following the CS-26A valve fail-ure (IR 50-271/88-20 Section 7.2).
The motor brake cover bolts were tightened to 30 ft-lbs in accordance with MR 88-3320 (CS-12B) and MR 88-3322 (CS-12A). Although not believed to have contributed to 'the CS-12A motor brake failure, the licensee is continuing to evaluate the cause and potential impact of the loose motor brake cover bolts.
The inspector will continue to monitor the licensee evaluations and actions-concerning this problem.
7.2 UPS-1A Inoperability At 5:10 p.m. on January 4, concurrent with the inoperability of the
"A" core spray loop (Section 7.1), the UPS-1A was declared inoperable for unrelated causes.
An Unusual Event was declared and is docu-mented in.Section 6.2.
The UPS-1A was declared inoperable following an observed high voltage reading of 532V.
Initial indications revealed a blown inverter leg fuse.
Further comprehensive troubleshooting identified several failed components associated with inverter leg number 6.
The remainder of the system.was unaffected. Maintenance department per-sonnel. replaced the failed number 6 inverter leg, inverter leg fuse (175A) and trigger fuse (SA), restarted the system and observed r.or-mal system operation The system was post-maintenance tested satis-factorily and returned to service at 1:30 a.m.
on January 5.
The UPS-1A remained operable through the conclusion of the report period.
The licensee response to the UPS-1A inoperability was prompt and well controlled. Troubleshooting and repair activities were conducted in accordance with procedures and technical manuals and were accurately documented in MR 89-0028. The inspectors had no further questions.
7.3 UPS-1B Inoperability On January 14, at 4:00 p.m., a trouble alarm for the UPS-1B annun-ciated.
The initial indication was a blown inverter leg fuse. Main-tenance troubleshooting identified a blown trigger fuse for inverter legs 11 and 12. Also a leaking capacitor (C9) in the transient sup-
-pressor network shorted several capacitors on inverter leg 12. The C9 and shorted capacitors were replaced, as were the leg 12 inverter and trigger fuses. The unit was post-maintenance tested and returned to service at 8:45 p.m. on January 14.
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The licensee corrective maintenance was effective in expeditiously returning UPS-1B'to service.
Activities were accurately documented in ' MR 89-0124. Although the root causes of these specific failures were not identified, the licensee is continuing to assess UPS opera-ting problems and overall reliability. The inspectors had no further questions.
' 8.
Radiological Controls 8.1 Conta'inment Air Monitor' Isolation l
On January 9,1989, the licensee found that the containment continu-ous air monitor (CAM) was isolated by a radiation protection (RP)
department technician while performing routine containment air grab sampling.
The sample is obtained from the same suction-side piping that supplies the CAM but uses separate equipment for the sampling.
Procedural controls during this process require that the suction flow path to the CAM remains open. An unapproved draft revision to the procedure was. developed -that altered the sampling process and re-quired the CAM to be isolated when obtaining a grab sample.
The draft revision was provided to the technician performing the routine grab sample with instructions to walkthrough the new procedure to determine usability-and correctness. The technician mistakenly used
. the unapproved procedure to obtain the sample and consequently iso-lated the CAM.
The error was identified approximately six hours
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later by an auxiliary operator. The CAM was subsequently returned to normal operation by RP department personnel. Plant-TS 3.6.C.2 allows the CAM to be inoperable for up to seven days, thus, a TS limiting condition for operation was not exceeded. However, failure to follow an approved procedure is a-violation of TS 6.5.A.
Several deficiencies were identified during the review of this occur-rence.
First, inadequate direction was given to the RP technician.
Second, the technician used an unapproved procedure to operate plant equipment. Third, the technician did not fully recognize the conse-quences of isolating a TS-required system.
Fourth, adequate guide-lines and training for proper procedure walkthroughs do not exist.
The licensee took effective short-term corrective actions to address these deficiencies as described in LER 89-02 (see Section 9.3). Long-term corrective action to address the weakness in procedure walk-through guidance is in process.
Because this violation of TS 6.5.A was identified by the licensee, was of a low severity level, had prompt corrective actions taken, was reported as LER 89-02, and was not related to corrective actions for a previous violation, no Notice of Violation will be issued in this instance.
Corrective actions appear effective to prevent recurrence and this licensee identified item is closed (50-271/89-01-01).
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9.
Licensee Event Reporting (LER)
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The-inspector reviewed the licensee event reports (LERs) listed below to
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determine =that with respect to the general aspects of the events:
(1) the
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L report was submitted in a timely manner; (2) description of the events was accurate; (3) root cause analysis was performed; (4) safety implications were considered; and (5) corrective actions implemented or planned were l
sufficient to preclude recurrence of a similar event.
9.1-LER 88-15 The LER 88-15, " Unidentified / Unqualified Reactor Building Vital Fire Barrier" described a licensee discovery that the penetration seal between the Reactor and Turbine Buildings in the area of the main steam and feedwater piping was not a fire-rated assembly. This event was previously reviewed in IR 88-20 Section 6.3.
'The.LER was well-
< written. and accurately described the problem, root cause analysis, o
and corrective. action plan.
Licensee commitments contained in the LER are being tracked under separate open items. The LER fulfilled the above criteria and no reporting deficiencies were identified.
9.2 LER 89-01 The LER 89-01, " Potential Loss of Secondary Cuntair. ment Due to Design and Personnel Error" addressed a design deficiency in the reactor building railroad access door seals that could affect secondary con-tainment integrity. Also covered in this LER ras un actual degrada-tion of secondary containment capability during installation activ-ities to correct the design deficiency.
This event is more fully described in Section 10.1 of this report.
The LER fulfilled.the above criteria and no reporting deficiencies were identified.
9.3 LER 89-02 The LER 89-02, " Inadvertent Isolation of Containment Air Monitor" addressed a situation where the containment air monitor was inadver-tently isolated by a technician conducting a walkthrough of an unap-proved sampling procedure.
Section 8.1 of this report more fully describes the circumstances of this event. Although the description and analysis of the event were geterally well-covered in the LER, the licensee determined that an additional event causal factor was lack of adequate training, but this factor was not included in the LER.
An informal licensee survey of several plant services disciplines indicated various levels of confusion existed as to what constitutes
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a: procedure walkthrough.
Anothe'r deficiency 'identifiedL in the LER.
involving the technician's lack. of knowledge or understanding of appropriate technica1' specifications was not addressed in the pro-posed licensee corrective actions.
With the exceptions : noted, the LER fulfilled the above criteria and.no major reporting deficiencies were identified.
The inspector. determined that the contributing causes and corrective actions were identified fully in the. licensee's
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internal corrective. action tracking system.
A revised LER is not required.
10.
Engineering Support 10.1 Potential Degradation of Secondary Containment Integrity On. January 3,1989, the NRC resident staff informed the licensee of an existing condition that could potentially result in a degradation or loss of. secondary. containment integrity. The specific concern was that the pneumatic seals on the reactor building r' ilroad access a
doors were supplied by the non-safety grade instrument air system.
The reactor building railroad access is provided to allow for large materials to be moved into the reactor building. There is an inner door and an outer door.
Only one door is opened at a time.
Each door has an inflatable seal that is pressurized to ensure that that
' door maintains secondary containment integrity. The door seals are supplied by.the instrument air system.
Both doors are provided by a single line that branches into two separate systems for each door.
This is to allow each door to be opened from either side.
These seals are normally pressurized in order to seal the access door open-ing when secondary containment is - required.
Because the instrument air system is non-safety grade, its loss must be assumed during design basis and seismic events. Loss of the pressure source to the seals would cause them to deflate and eventually lose their sealing ability.
Loss of these seals would probably jeopardize secondary containment integrity by allowing by pass air flow that would exceed the capacity of the standby gas treatment (SGT) system.
Loss of the SGT system capability to maintain sufficient negative pressure inside the reactor building would indicate a degradation or loss cf secondary containment integrity.
The licensee evaluated the situation and on January 4,1989, deter-mined that an unanalyzed condition existed. Notification per 10 CFR 50.72 was properly made to the NRC on January 4.
An analysis and justification for continued operations (JCO) was developed by the licensee, approved by the Technical Services Superintendent (TSS),
included in the 10 CFR 50.72 notification, and provided to the NRC re.ident staff on January 5.
The JC0 is summarized below.
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Continued plant operation is -justified since there is ~ a high;proba-bility. that the instrument air system integrity will' be maintained-based on the'following' considerations:
iThere is a very low probability of a significant seismic event
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occurring over the next few months.
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There is a good possibility that the instrument air system would'
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remain functional following a seismic event.
This system was originally designed to. be seismic in the original plant con-struction.
Engineering judgement demonstrates-that. existing pipe supports would.be adequate to prove-seismic qualification of the existing instrument air system. Multiple check valves in the system provide further assurance that a breach in one part-of 'the system would not necessarily degrade thei entire system.
.TheseLseals do.not require high pressures. Existing procedures
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Jaddress.' operator response to a loss of instrument air pressure and require _ a manual scram if the air header pressure falls below:55 psig.
These seals would still be functional at - this pressure.
The seal ' pressure is verified by operator rounds once per shift.
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Any degradation of the seal pressure would be identified.
Instrument air pressure is indicated in the control room, and.a-
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low pressure condition - would be alarmed, thus providing~ the operators with early indication of a loss of. instrument air.
In summary, the licensee justified continued plant operation based on
.the low probability of a seismic event occurrence. in the remaining period-prior to the - scheduled refueling outage and the. inherent seismic capabilities of the instrument air system. as originally designed and installed.
After review of the JCO, the NRC resident staff informed the licensee on January 5 and 6, that further licensee-development, analysis, and evaluation of potential interim repairs or modifications to better ensure continued secondary containment integrity were required.
Additionally, although the JC0 appeared adequate for the short term, any interim modification needed to be implemented expeditiously. An _ interim passive seal repair was evalu-ated, selected and subsequently installed on January 10. The passive seal is an elastic, medium-density, closed-cell, neoprene foam rubber-gasketing material. The passive seal was installed with the inflat-able seal pressurized.
This caused the door to be pushed away and against the steel frame; thus increasing the gap (to be sealed) to l.
it's. maximum possible dimension. This sequence of installation pro-vided the following benefits and assurances:
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and the plant continued to operate in a normal manner without possibility of impact to' secondary containment integrity during passive seal installation.
The maximum gap to be sealed was visible at time of installa-
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tion, _thus enabling the _ installer to adjust gasket size as l
I required to assure a proper and adequate seal along the entire perimeter.of the door.
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to its tight fit and elastic properties.
In the unlikely event of a loss of air supply to the inflatable
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seal, the ' inflatable seal would relax, causing the " passively-sealed" gap to decrease slightly.
This would cause a slight increase in the compressing forces on the passive seal, thus increasing.its sealing capabilities as well as it's ability to remain in place.
The inherent flexibility of the passive seal and its very tight
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fit provides_ good assurance that the seal will remain intact-during thermal cycling or a seismic event with or without the existing inflatable seal.
An example of the repair appears as Attachment A to this report. The gasket would provide a " passive seal" on the inner access door even if the installed pneumatic seal deflated.
An unintentional partial test of the adequacy of the passive seal occurred during installation.
The design of the control logic for the access doors isolates the door seals from the instrument air sys-tem and locks in seal pressure upon a loss of power.
Thus, the seal air pressure is dependent on system leakage. When the passive seal was being installed on the inner door, personnel tagged open the switches on both of the inner door control panels de-energizing the system.
The system was tagged to prevent personnel injury.
This action isolated the pressure inside the seal but subsequent manifold leakage reduced the pressure.
After installation of the passive seal, personnel noticed that the inner door seal pressure was
"0" psig.
During passive seal installation, reactor building differen-tial pressure data showed that secondary containment integrity was maintained by normal ventilation. The licensee committed to a func-tional test of the passive seal using only the SGT system (normal secondary containment integrity test) after reactor shutdown and prior to refueling operations.
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The. licensee subsequently developed a permanent repair / modification u
for_the access door seals.
Implementation of the repair will' follow receipt of required materials and accomplishment is anticipated in March 1989. Review of the adequacy: of thel repair ~ and post-installa
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tion test data.is an unresolved item (50-271/89-01/02).
Findings The initial licensee response to this situation was. disjointed. 'Al-though the licensee was still in the process' of responding to NRC
. Generic Letter (GL) 88-14, " Instrument Air System Problems", initial engineering determinations indicated this situation was not a. prob-lem.
.It appears that. final sup'ervisory. review of the completed response. might. have ; identified - and corrected this error.
The first
' indication that a potential problem existed was provided by the.NRC resident staff.
The licensee required a full day to address the issue and arrive.at the conclusion that a potential unanalyzed condi-tion existed.
Once the ' licensee verified the condition existed, development of a JC0 was completed.
However, the JC0 relied upon probabilities and engineering' judgement without addressing potential'
interim ' repairs that would at least temporarily increase confidence in secondary containment integrity. Although technical solutions to-the situation were being discussed internally, the licensee did not see the need for expedited evaluation and implementation. After dis-cussions with the NRC resident staff, the licensee accelerated for-mulation and evaluation of potential. interim repairs. ' A relctively simple and easily installed repair was subsequently identified, reviewed, approved and installed in a timely manner.
Licensee initial resistance to this process indicated a diminished sensitivity to the importance of ensuring secondary containment integrity is maintained under all operating and design basis conditions.
The licensee had no formal ~ method for_ development, review, and ap-proval of a JCO.
The original JC0 was approved at the TSS level.
Although aware of the situation and the basis for the JCO, plant man-ager formal approval and concurrence was not documented.
The resi-dent inspector discussed the lack of review and approval with the plant manager and indicated that plant operations review committee (PORC) responsibilities, in accordance with technical specification (TS) 6.2.A.6, require PORC review of plant operations including l
potential unanalyzed conditions. A PORC was subsequently convened on January 11, to review the event.
A. revised JC0 was approved by the PORC and subsequently reviewed and approved by the plant manager. A one-week delay by PORC to review an unanalyzed condition affecting safety and the attendant engineering evaluation that would allow continued plant operations is excessive and indicates a lack of licensee understanding of PORC responsibilities. Licensee review and corrective action to ensure that the PORC fulfills all required responsibilities is an unresolved issue (50-271/89-01-03).
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10.2 Reactor Building-to-Torus Vacuum Breaker Design Background During system reviews and evaluations performed in accordance with NRC Generic Letter 88-14, " Instrument Air System Problems", the licensee was informed by both the NRC resident staff and another licensee of a potential design deficiency with the reactor building-to-torus vacuum breakers.
The vacuum breaker assembly is comprised of two valves:
an instrument air operated butterfly valve and a swing check valve.
Both valves are normally closed.
However, the butterfly valves (V16-19-11A & B) f ail open upon loss of instrument air leaving the check valves as a single barrier for maintaining pri-mary containment integrity.
The v a c u o... breakers are designed to limit a. potential negative pressure in the suppression chamber under
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post-accident conditions. If suppression chamber pressure drops to a negative 0.50 psi (pounds per square inch), the butterfly valves open allowing reactor building air to be drawn through the check valves into the chamber.
Failure of the butterfly valves in the open posi-tion does not affect the vacuum relief function of the assemblies.
However, failure in the open position does reduce primary containment integrity to a single valve.
Because the instrument air system is non-safety grade, its loss must be assumed for all design basis acci-dents and seismic events.
Technical specification table 4.7.2.a,
" Prima ry Containment Isolation Valves Valves Subject to Type C
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Leakage Tests", includes the butterfly valves as well as the check valves (V16-19-12A and B). Technical specification 3.7.D.1 requires that all isolation valves listed in table 4.7.2 be operable during reactor power operation.
Technical specification 3.7.0.2 provides relief from 3.7.D.1 requirements if at least one valve in any line containing an inoperable isolation valve is in the trode corresponding
to the isolated condition. Because the butterfly valves must be con-
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sidered inoperable from a containment integrity design standpoint due to their failure position, the licensee implemented the relief al-lowed by TS 3.7.D.2 and verified the check valves were closed.
In accordance with TS 4.7.D.2, this verification was performed and logged in the control room on a daily basis.
Although licensee actions fulfilled TS requirements, the issue of the l
design basis sufficiency still existed.
This issue was addressed at
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. a PORC meeting on January 20, 1989.
The engineering evaluation of the design basis was reviewed at the PORC meeting and is summarized j
below.
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17-l The vacuum breaker assemblies have a dual safety function. Based on the GE design-specification, the primary function is contain-
- ment vacuum relief to limit the negative pressure that the con.
tainment may be subject to during post-accident conditions, or normal operations.
"The primary. containment vacuum relief. system shall be utilized-to limit the negative pressure that the containment may be sub-jected to during post-accident conditions, or normal operations.
Vacuum relief air is automatically supplied to the < suppression chamber if-the internal pressure drops to a negative 0.50 psi.
The pressure ' suppression chamber vacuum relief. device
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draws ~ air from 'the secondary containment.
Two (2) vacuum breakers in series.shall be utilized in each of two (2) parallel lines to the reactor building. One valve will-be actuated by, a-differential. pressure. signal, the second valve will be self-actuating.":(GE specification 22A1265 - Design Specification -
Reactor Containment).
The above function is the only reason for including this penetratio'n in the containment. design..Given that the original designers pro-vided this vacuum relief penetration, the secondary function-of the valves is primary containment. isolation.
Review of original design documents and the FSAR indicates that this penetration is an exception to typical class B containment penetra-tions.
Design documents state that only one remotely operated or self-actuated valve is required for lines which open into the sup-pression chamber.
" Lines which open into the suppression chamber, and whose branches do not terminate in dead end service capable of with-standing. suppression chamber design conditions, shall utilize one remotely operated or self-actuated valve (example:
High pressure coolant injection system and reactor core isolation cooling system).
Exceptions to the above are suppression chamber vacuum relief lines, which utilize self-actuated and power operated valves in series; and lines which are considered extensions of the con-tainment (core spray, residual heat removal and high pressure coolant injection) shall utilize no automatic isolation valves."
(GE Specification 22A2856 - Design Specification - Atmospheric Control, Primary Containment)
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The. original Safety Evaluation for VYNPS dated June 1, 1971, (Section 5.2.4) states that lines that penetrate the containment, but commun-icate only with containment, are equipped with at least one isolation i
l valve located outside of the containment.
Accordingly, the vacuum breaker lines at VYNPS are provided with check valves for-providing the isolation function.
The air-operated valve provides an addi-tional. degree of isolation under most circumstances. General Design u
' Criterion (GDC) 56' generally requires two isolation valves unless it
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can' be demonstrated that the lines are acceptable - on some other-defined basis.
The :riterion also stipulates that upon' loss - of actuating power, automatic isolation valves shall be designed to take l
the position that provides the greater safety.
FSAR Table 5.2.2 lists only the check valve as a containment. isola-tion valve where Table 7.3.1 lists both 'the check valve and the air operated valve, but denotes this penetration as a special case. This is consistent.with the original GE design specification from which
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the FSAR was derived and to which VYNPS was licensed.
Although TS Table 4.7.2.2 lists the butterfly valves as leak tested containment isolation valves, this does not negate the special design basis 'that was intentionally applied to these valves licensed in 1971.
VYNPS considers this testing an added degree of conservatism which strengthens the performance of both the vacuum breaker and
. containment isolation functions by applying testing requirements to both valves.
In summary, VYNPS maintains that the butterfly valves that are part of vacuum breaker penetrations were originally designed with dual safety functions. They were also originally specifically designed to open upon loss of the instrument air system. VYNPS considers these valves operable and in compliance with the current licensing basis.
This penetration required special considerations during the original design of the plant, and these considerations were documented and licensed in 1971.
The licensee believes that the butterfly valves are primarily in-stalled to support the vacuum breaker function and only secondarily provide a containment isolation function.
Therefore, the licensee concludes the open failure position for these valves is correct in that it supports their intended primary function of providing vacuum relief if required. This aspect of the issue appears to be generic and is being specifically addressed by the BWR Owner's Group (BWROG).
The NRC:NRR is aware of this potential generic issue. Resolution of the issue appears to be subject to being addressed by the BWROG and NRC:NRR review of licensee submittals required by NRC Generic Letter 88-14.
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Findings
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The licensee response to id3 notification of this issue was more orderly and prompt than it was to the access door issue (Section 10.1).
Engineering evaluation and design basis rationale were thorough and well presented. This issue was presented to the PORC in a timely manner.
Although the licensee considers invoking the re-quirements of TS 3.7.D.2 and 4.7.D.2 overly conservative, the NRC resident staff considers the actions consistent with the plant TS and mandatory. The difference in views stems from the licensee position that the butterfly valves are not primarily containment isolation valves, that the design basis supports this premise, and that inclus-j ion as TS containment isolation valves was a conservatism to support i
minimizing potential primary containment penetration leakage.
Al-though continued operation in this condition is allowed by the TS, a timely resolution of the issue is required to solidify the actual design basis in order to support design and implementation of any system modifications that might prove to be necessary. Resolution of the design basis for the vacuum breakers is an. unresolved issue
(50/271/88-01-04).
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10.3 Fire Protection System Material Issue Deficiencies Since September 1988, the licensee has identified three occurrences of components that had been issued and installed in various plant'
fire protection systems without certification of proper QA procure-i ment standards. Appendix C of YOQAp-1A (licensee QA program manual)
requires that graded quality assurance must be applied to fire pro-tection components servicing safety-related areas.
However, on i
November 16, 1988, a failed battery charger / transfer module (BC-31)
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in the control room fire protection panel was replaced with a non-certified module. On January 9,1989, an I&C engineer identified the error during certification review of the failed module.
Certifica-tion of the installed module was subsequently obtained from the ven-dor via telefax January 10. Additionally, on January 12, the licen-
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see determined that a cable vault fire protection panel relay in-stalled as a one-for-one replacement in September 1984 was issued from non-QA certified procured stores.
Previously, following the September 1988 actuation of the east switchgear room carbon dioxide fire suppression system, the licensee determined that the electro-
thermal links installed in the ventilation damper isolation circuit
were procured without QA certification.
Following identification of
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each occurrence, the licensee generated the appropriate report to
obtain certification or replace the affected component.
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The inspectors previously identified various weaknesses in the imple-mentation of the fire protection program. The occurrences above are-indicative of similar weaknesses. Technician training appears to be
insufficient to ensure appropriate knowledge with respect to fire
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protection component procurement certification requirements.
Fur-ther, the direction of a department instruction (DI-Temporary Change)
to.the material issue procedure, AP 0808, revision 5, provided con-tradictory instruction to technicians.
In an attempt to clarify material issue requirements, the DI added an EQ and a fire protection check-off to the safety and non-safety classification section of the material issue form.
The DI instruction directed for safety-related issues only to indicate if either EQ or fire protection are appli-cable. However, all fire protection systems are non-safety related, therefore, technicians could be misdirected by the DI rather than prompted to address fire protection component procurement certifica-tion requirements.
As a result of the previous inspector concerns regarding fire protec-tion program deficiencies, the licensee was required to inform Region I in writing (IR 88-20) of implemented and proposed corrective i
actions to ensure programmatic requirements are obtained. In lieu of the occurrences above, the scope of the improvement program should be revised to ensure that appropriate technician training and procedure i
revisions are accomplished. The inspectors will continue to observe licensee performance in this area and this concern will be added to previously unresolved issue 88-14-02.
The inspectors had no further questions.
11.
Review of Licensee Response to NRC Initiatives 11.1 Review of NUREG-0737 Commitments On January 23 and 24,1989, the installation progress of the Safety Parameter Display System (SPOS) at Vermont Yankee Nuclear Power Cor-poration (VYNPC) was reviewed by an NRR Project Engineer.
The inspection purpose was to support an NRC decision on a licensee request for relief from a Commission confirmatory order, June 12, 1984, which confirmed the implementation dates for certain items relating to Supplement 1 to NUREG-0737, modified August 29, 1985, to include additional commitments the licensee had made pertaining to the schedules for SPDS and Regulatory Guide 1.97 requirements. These schedules specify a functional SPOS system be installed prior to start-up of Cycle 14, scheduled for April 198 _
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(l Through interviews with ' the licensee. cognizant representative, lead project engineer, review of' the system status documents submitted by the licensee, walk-downs of the completed areas at both the plant and L
simulator, and activities pertaining to the installation and opera-tion of.SPDS, it appeared that the.. licensee is making significant-progress towards final completion of the SPDS. SPDS is a part of the new licensee system called ERFIS, which includes additional plant-monitoring and analysis -to be used on a'. regular basis by-operators and engineering staff.
There are three major activities associated-with SPDS which determine
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- overall completion of the project.. Activities completed to date:
(1)
Installation. This includes wiring of the Data Acquisition Sys-tem (DAS), new signal terminators, operator workstations in the
. control - room with SPDS terminals, uninterrupted. power supply system,- computer ' room expansion, new. conduit, and connecting wiring between components.
These activities are 83% completed.
(2) Design-of Hardware & Software.. Hardware includes the DAS. com-puter, the SPDS computer, and the linking devices between the plant, DAS computer, and the SPDS computer, 100% completed.
Software includes the SPDS sof tware, 100% complete, and :DAS software, 80% complete.
(3) Testing.
The testing of the SPDS will be done in various stages, starting with factory authorized testing (FAT), site installation testing, and final operability testing. The licen-see indicated that all testing that can be completed without the DAS computer will be done before start-up Cycle 14. To accom-plish this goal the licensee has incurred the additional expense of purchasing redundant hardware from their contractor.
To date, 65% of the FAT has been completed, with the majority of the remaining testing to be done once the DAS computer is installed at Vermont Yankee.
Based on licensee estimates and direct observation, completion of overall SPDS installation, to date is about 80%. This inspection and review of the current anticipated completion schedule will be con-sidered by NRC:NRR in reviewing the licensee request of January 5, 1989, to extend the schedular requirement that SPDS be functional at start-up for Cycle 14.
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11.2 IE Bulletin 85-03-Supplement I to IE Bulletin 85-03, " Motor Operated Valve Common Mode Failures During Plant Transients Due to Improper' Switch Settings",
i was issued on April 27,1988,. and requested licensees ' to provide additional information in clarification of the original IE Bulletin 85-03. As requested by action item e. of-Supplement 1, the licensee
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response of June 2,1988, in conjunction.with the licensee letter. of May. 5,1988, submitted per an NRC Request for Additional Information, identified the additional valves to be addressed in their program in response to -the original bulletin.
Review' indicates that the licen-see selection of the additional valves to be addressed in their pro-gram meets the requirements of action item e. of Supplement 1 and is i
acceptable. The results of inspections to verify proper inclusion. of
' these valves in the bullnin program will be addressed during ' routine inspection activities.
12.
Review of Periodic and Special Reports-Upon receipt,.the inspector reviewed periodic and special reports submit-ted. pursuant to Technical Specifications..This review verified, as appli-cable:
(1) that the reported information was. valid and included the NRC required data; (2) that test results and supporting information were con-sistent with design predictions and-performance specification; and-(3) that planned corrective actions were adequate for resolution of the problem. The inspector also ascertained whether any reported information should be classified as an abnormal-occurrence.
The following reports
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were reviewed:
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Monthly Statistical Report for plant operations for the month of December 1988 and January 1989.
13. Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss the findings.
A summary of findings for the report period was also discussed at the conclusion of the inspec-tion and prior to report issuance, No proprietary information was iden-tified as being included in the report.
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13.1 Licensee Requested Management Meeting
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p l0n January 26, 1989, a management. meeting. wasl held at. licensee.
.
request (see Attachment B for Meeting Notice) in.the ' Region I office (see. Attachment-C for ; attendees).
Matters discussed during.' this:
meeting. included the:' results of ailicensee performed safety system functional inspection -(SSFI), preventive maintenance program, main-tenance' organization, : vendor :information program, plans and l schedule
'
for the 1989 refueling outage 'and result's of the licensee ~ task force investigation of the - high radiation door - tampering incident (see Attachment 0 for' licensee. presentation material).
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ATTACHMENT A
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MR 89-Q%3 ATTAcHM&MT.1
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141 t p ATTACHMENT B
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U.S. NUCLEAR REGULATORY COMMISSION
.No.89-004
REGION I
i NOTICE OF SIGNIFICANT LICENSEE MEETING Licensee:
Vermont. Yankee Nuclear. Power Corporation Facility:
Vermont Yankee Nuclear Power Station Docket No.:
50-271 iTime and.Date:
.9:30 a.m., January 26,.1989 Location:
NRC Region I, King of Prussia, Pennsylvania Division of Reactor Projects (DRP) Conference' Room Purpose:
Discussion of the Status of.the Following Topics:
1.
Vendor Manual Update. Program 2.~
Licensee Conducted Safety System Functional Inspection 3.
Outage Plans and Highlights 4.
High Radiation Area Door Tampering. Status NRC Attendees:
W.. Kane, Director, Division of Reactor Projects (DRP)
S. Ebneter, Director, Division of Radiation Safety and Safeguards (DRSS)
T. Martin, Director, Division of Reactor' Safety (DRS)
J._Wiggins, Chief, Reactor Projects Branch No. 3, DRP
.
R. Bellamy, Chief, Facilities Radiological Safety and Safeguards Branch, DRSS J. Durr, Chief. Engineering Branch, DRS d,
B. Gallo, Chief, Operations Branch, DRS C. Anderson, Chief, Plant Systems Section,.DRS N. Blumberg, Chief, Operational Programs Section, DRS M. Shanbaky, Chief, Facilities Radiation Protection Section, DRSS D. Haverkamp, Chief, Reactor Projects Section No. 3C, DRP G. Grant, Senior Resident. Inspector R. Wessman, Director, Project Directorate I-3, Office of Nuclear Reactor Regulation (NRR)
M. Fairtile, Project Manager, NRR Licensee Attendees: J. Pelletier, Plant Manager, Vermont Yankee Nuclear Power Corporation (ViNPC)
P. Donnelly, Maintenance Superintendent, VYNPC J. Herron, Technical Programs Manager, VYNPC R., Reid, Operatiors Support Manager, VYNPC J. Thayer, VY Project Engineering Manager, Yankee Atomic Electric Company (YAEC)
5. Miller, VY Project Manager, YAEC L. Trembley, Senior Engineer, YAEC
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Meeting Notice No,89-004
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l Note: Attendance by NRC personnel at this meeting should be made known by January 24, 1989, via telephone call to Don Haverkamp, Region I, at FTS 8-346-5120.
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Prepared by:
Doliald R. Haverkamp, Ch{ef, RPS 3C Distribution V. Stello, Jr.. Executive Director for Operations
-
J. Taylor, Deputy Executive Director for Regional Operations B. Grimes, Director, Division. of Reactor Inspector _and Safeguards, NRR J. Lieberman, Director, Office of Enforcement
L. Chandler, Assistant General Counsel for' Enforcement T. Murley, Director, Office of Nuc' ear Reactor Regulation F. Miraglia, Associate Director for Inspection and Technical Assessment, NRR S. Varga, Director, Division of Reactor Projects - I/II, NRR B. Boger, Assistant Director for Region I Reactors, NRR R. Wessman, Director, Project Directorate I-3, NRR V. Rooney, Project Manager, PD I-3, NRR M. Johnson, Regional Coordinator, EDO Public Document Room (PDR)
local Public Document Room (LPDR)
State of Vermont State of New Hampshire NRC Resident Inspector bec:
.
Regional Administrator Deputy Regional Administrator Division Directors
' Branch Chiefs Section Chiefs Public Affairs Officer J. McGrath, RI M. Miller, RI J. Gutierrez, RI
.
D. Holody, RI fiegion I Receptionist DRMA Files DRP Files Bulletin Board M. J. DiDonato, DRP i
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7-e yl,
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s ATTACHMENT C Vermont' Yankee Management Meeting Attendees January 26, 1989
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,Name/ Title U.S. Nuclear Regulatory Commission-J. Wiggins, Chief, Reactor Projects Branch No. 3, DRP, RI-D. Haverkamp, Chief, Reactor Projects Section No. 3C, DRP D. Dempsey, Reactor Engineer, DRP, RI
.
G. Grant, Senior Resident Inspector, Vermont Yankee
- T. Martin, Director, Division of Reactor Safety (DRS), RIL J..Durr, Chief, Engineering Branch, DRS, RI N. Blumberg, Chief, Operational Programs Section, DRS, RI
-
R. Bellamy,- Chief, Facilities Radiological' Safety and Safeguards,. Division -
of Radiation Safety and Safeguards (DRSS), RI R. Loesch,~ Radiation Specialist, DRSS, RI.
.
R..Wessman, Director, Project' Directorate I-3, Office of Nuclear Reactor Regulation (NRR)-
Vermont Yankee Nuclear Power Corporation L. Tremblay, Senior Engineer P. Donnelly, Maintenance Supervisor J.- Herron, Operations Supervisor R. Lopriore, Maintenance Supervisor D. Reid, Operations Support Manager J. Pelletier, Plant Manager Public l
W. Sherman, Nuclear Engineer, State of Vermont
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INSPECTION (
PRI OBSERV.NO.
ISSUE DESCRIPTION RESPONSIBILITY
]
VY-WRB-1 LACK OF ADEQUATE CAPACITY OF THE PLANT /TSS EMERGENCY DIESEL GENERATOR AIR START RECEIVERS
VY-WRB 2 DESIGN / OPERATION OF THE DIESEL FUEL PLANT /TSS OIL DAY TANK IS IN DISAGREEMENT WITH FSAR
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VY-SMK-4 THE EFFECTS OF REDUCED FLOW TO PLANT /TSS SAFEW RELATED COMPONENTS IN THE SVCE WTR SYSTEM RESULTING FROM LOSS OF AIR TO THE FAllOPEN DIESEL GEN. COOLING WTR FLOW CONTROL VALVE HAVE NOT BEEN EVALUATED
VY-RLG-4 SERVICE WATER TO EDG DID NOT ACHIEVE PLANT /TSS DESIGN FLOW DURING SURVEILLANCE
VY-WCS-7 MORE THAN HALF THE ENVIRONMENTALLY PLANT /MS QUALIFIED LIMITOROUE MOTOR OPERATOR VALVES HAVE NOT HAD GREASE CHANGEOUT OR SPRING PACK INSPECTION SINCE THE ORIGINAL INSTALLATION
VY-WCS-3 NON-PERFORMANCE OF VENDOR RECOM-PLANT /MS MENDED PREVENTIVE MAINTENANCE
VY-WRB-3 DESIGN WEAKNESS IN THE SENSING LINES PLANT /TSS
FROM STANDBY DIESEL GENERATOR AIR START RECElVERS TO PRESSURE SWITCHES THAT CONTROL AIR COMPRESSORS
,
VY-WRB-4 LACK OF TESTING OF CHECK VALVES IN THE PLANT /TSS DIESEL GENERATOR AIR START SYSTEM
VY-WRB-5 LACK OF ADEQUATE LOGIC TESTING OF THE PLANT /TSS HPCISYSTEM
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PAGE 2 INSPECTION -
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PRI OBSERV.NO.
ISSUE DESCRIPTION RESPONSIBILITY
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VY-SMK-2 NO DOCUMENTED SUBSTANTIATION EXISTS PLANT /TSS FOR THE METHODOLOGIES AND PRO-CEDURES USED TO SUPPORT CONDUlT FOR PLANT MODIFICATIONS.
2 VY-SMK-6 HEATING LAMPS INSTALLED BY PLANT /MS MAINTENANCE REQUEST TO KEEP HPCI
'
TURBINE BEARING HOUSING WARM MAY '
NOT BE SEISMICALLY ANCHORED OR QUALIFIED TO WITHSTAND A SEISMIC DISTURBANCE
VY-WCS-1 THREE OF FOU'R STARTING TANKS ON PLANT /MS EMERGENCY DIESEL GENERATORS A AND B HAVE CERTIFICATES OF BOILER AND PRESSURE VESSEL INSPECTION THAT HAVE EXPIRED
,
VY-WCS-6 SPEAKER IN DG ROOM B TURNED TOWARD PLANT /MS WALL AND MUFFLED WITH A RAG
VY-WCS-5 DIESEL GENERATOR MINIMUM LUBE OIL PLANT /MS PRESSURE REQUIREMENT OF 20 PS!G IS SET BELOW MANUFACTURERS RECOM-MENDED MINIMUM PRESSURE OF 26 PSIG.
VY-WCS-4 THE CURRENT HPCI LUBE OIL FILTER HIGH PLANT /MS DP SETPOINT IS SET ABOVE THE FILTER INTERNAL BYPASS FULLY OPEN POSITION
VY-WCS-2 THE MAINTENANCE RECORDS (VISI-PLANT /MS RECORDS) CONTAIN CONFLICTING PREVENTIVE MAINTENANCE REQUIREMENTS AND WORK SUMMARY DESCRIPTIONS
VY-SMK-5 INCONSISTENT SAFETY DESIGNATIONS ON PLANT /MS MAINTENANCE REQUESTS FOR SAFETY RELATED LOUVRE AIR ACTUATORS IN DIESEL GENERATOR ROOM B.
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PAGE 3 INSPECTION PRI OBSERV.NO.
ISSUE DESCRIPTION RESPONSIBILITY
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VY WCS-8 OIL SAMPLE RESULTS FOR HPCI PLANT /MS TURBINE AND DIESEL GEN. ARE NOT CONSISTENTLY RECORDED IN THE MAINTENANCE ENGINEERING FILES AND THEREFORE RECORDS ARE NOT AVAILABLE TO INDICATE IF ALL SAMPLES WERE ANALYZED.
.
VY-SMK-3 HYDROGEN CONCENTRATIONS FROM ALT.
PLANT /TSS SHUTDOWN BATTERY AS2 CHARGING IN DIES. GEN. RM.1 A MAY EXCEED CODE LIMITS.
VY RLG-3 DRAWINGS CONTAIN VARIOUS PLANT /TSS DISCREPANCIES
VY-WRB-6 MOTOR OPERATED VALVE RHR-V10-65A PLANT /TSS AND -65B VALVE ACTUATION TIME (AND SURVEILLANCE TEST ACCEPTANCE CRITERIA) MAY NOT BE ADEQUATE TO ASSURE ITS FULL STROKE OPEN POSITION CAN BE REACHED FOR ALL
VY-WRB-7 ACCEPTANCE CRITERIA FOR THE STOKE PLANT /TSS TIME OF SAFETY RELATED VALVES THAT EXCEEDS TIMES SPECIFIED IN THE FSAR AND EXCEEDS THE TIME REQUIRED FOR THE SYSTEM TO PERFORM ITS FUNCTION (HPCI)
VY-RLG-1 OPERATING PROCEDURE DOES NOT PLANT /OS PROVIDE SUFFICIENT GUIDELINES TO OPERATORS FOR MANUALLY LOADING DIESEL GEN. FOLLOWING A LOSS OF NORMAL POWER OR DEGRADED GRID CONDITION.
VY-RLG-2 UNCONTROLLED OPERATOR AIDS /
PLANT /OS
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LABELS ARE PRESENT IN THE CONTROL
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ROOM AND ON THE DIESEL GENERATOR
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A AND B LOCAL CONTROL PANELS a
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INSPECTION I
PRI OBSERV.NO.
ISSUE DESCRIPTION RESPONSIBILITY
VY-SMK-1 THE 125VDC BATTERY IN DIESEL PLANT /TSS GENERATOR ROOM 1A IS NOT PROTECTED FROM JACKET WATER COOLANT WHICH MIGHT SPILL FROM A DAMAGED SURGE TANK SIGHT GLASS DURING A SEISMIC
]
EVENT
.
W-WGD-1 AN INVALIDATED COMPUTER PROGRAM PLANT /TSS WAS USED TO CALCULATE CLASS lE 4160 AND 480 AC SHORT CIRCUIT ANALYSIS YAEC-1373
W-WGD-2 CIRCUlT BREAKER AND RELAY SETPOINT PLANT /MS SELECTION AND CONTROL HAS NOT BEEN ESTABLISHED.
.
W-WGD-3 THE CLASS lE DC SYSTEM DOES NOT HAVE PLANT /TSS AN APPROVED SHORT CIRCUlT ANALYSIS
VY-WGD-4 THERE IS INADEOUATE MOTOR OVERLOAD PLANT /MS PROTECTION
W-WGD-5 CERTAIN CALCULATIONS DONE AT YANKEE YNSD/EEG ATOMIC WERE NOT PERFORMED IN ACCOR-i DANCE WITH ANSI 45 2.11 OR YANKEE ATOMIC PROCEDURE WE-103.
VY-WGD-6 FAILURE TO CONSIDER THE POTENTIAL PLANT /TSS FOR OVERLOADING MOTOR CONTROL CENTERS 88 AND 9B DURING AN ACCIDENT WITH A SIMULTANEOUS LOSS OF NORMAL POWER
!
VY-WGD 7 A DIFFERENCE EXISTS BETWEEN WHAT PLANT /TSS ENGINEERING ASSUMED AS THE DIESEL LOAD PROFILE AND HOW THE OPERATORS MAY ACTUALLY LOAD THE DIESELS DURING A LOSS OF NORMAL POWER AND l
(
ACCIDENT CONDITION
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L.A. TREMBLAY YAEC 1/26/89 SSFI INSPECTION BASIC QUESTIONS TO BE ANSWERED 1. HOW IS THE SYSTEM OPERATED COMPARED WITH HOW IT WAS DESIGNED TO OPERATE?
2. HAVE MODIFICATIONS SINCE THE LICENSING OF THE PLANT ALTERED THE DESIGN IN A MANNER SUCH THAT IT MAY NOT FUNCTION AS EXPECTED?
3. ARE SYSTEM COMPONENTS AND COMPONENTS OF ESSENTIAL SUPPORT SYSTEMS PROPERLY MAINTAINED?
4. DOES POST-MODIFICATION TESTING CONFIRM THE READINESS OF THE SYSTEM IF CALLED UPON?
j 5. DOES SURVEILLANCE TESTING CONFIRM THE READINESS OF THE SYSTEM IF CALLED UPON? DO THE ACCEPTANCE CRITERIA ACCURATELY REFLECT THE DESIGN BASIS?
6. HAVE THE OPERATORS BEEN PROPERLY TRAINED TO OPERATE THE SYSTEM? ARE MODIFICATIONS ACCURATELY REFLECTED IN TRAINING DOCUMENTS?
.
7. ARE MANAGEMENT CONTROL PROGRAMS EFFECTIVE TO INSURE THAT THE SYSTEM WILL FUNCTION ON DEMAND?
8. HAVE MODIFICATIONS TO ESSENTIAL SUPPORT
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SYSTEMS ALTERED THE LIKELlHOOD THAT THE SAFETY SYSTEM WILL FUNCTION AS EXPECTED 7
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METHODOLOGY
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- INSPECTION MODELED AFTER NRC IE MANUAL, CHAPTER
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-lNSPECTION TEAM COMPOSED OF SENIOR LEVEL, HIGHLY QUALIFIED INDIVIDUALS (TOTAL OF 45 UTILITY & NRC SPONSORED DESIGN INSPECTIONS SINCE 1982)
I-INTERACTIVE INSPECTION-BETWEEN MEMBERS OF INSPECTION TEAM-BETWEEN INSPECTORS AND PLANT PERSONNEL-VERTICAL SLICE PROCESS:
PLANT SYSTEMS ll
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"l DESIGN ll PROCESSES ll El OPERATIONS ll
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"l MANAGEMENT
"l CONTROLS
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TEAM COMPOSITION
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ERCl/WESTEC INSPECTOR VY COUNTERPART TEAM LEADER
VY CORP. PROJECT ENGINEER ELECTRICAL DESIGN
- YAEC LEAD ELECT. ENGINEER MECHANICAL DESIGN
- YAEC SENIOR SYS. ENGINEER OPERATIONS
MAINTENANCE
- VY SENIOR MAiNT. ENGINEER SURVEILLANCE TESTING :
- VY MECHANICAL ENGINEER
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INSPECTION SCHEDULE WEEK #1- (INSPECTION BEGINS SEPTEMBER 7,1988)
INSPECTORS RECEIVE SITE ACCESS TRAINING, PERFORM INITIAL PLANT WALKDOWN, AND OBTAIN KEY DOCUMENTS.
WEEK #2
,
TWO INSPECTORS (ELECTRICAL AND MECHANICAL DESIGN)
INITIATE DESIGN REVIEW AT YAEC IN FRAMINGHAM, MA.
WEEK #3 FOUR INSPECTORS COMMENCE INSPECTION AT THE PLANT.
DESIGN TEAM (TWO INSPECTORS) CONTINUE AT YAEC.
WEEK #4 INSPECTORS CONTINUE REVIEW AT ERCl/WESTEC OFFICES.
WEEK #5 FOUR INSPECTORS RETURN TO PLANT TO CONTINUE REVIEW.
DESIGN TEAM (TWO INSPECTORS) CONTINUE REVIEW AT YAEC.
PRELIMINARY CONCLUSIONS PRESENTED TO VY & YAEC.
WEEK #6 I
INSPECTORS COMPLETE TECHNICAL REVIEW AND FINALIZE
.
l OBSERVATIONS AT ERCl/WESTEC HOME OFFICE.
WEEK #7 J
DRAFT REPORT PREPARED AND SUBMITTED TO VY FOR REVIEW.
FINAL REPORT ISSUED NOVEMBER 18,1988.
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RESULTS OVERALL CONCLUSION: EDG AND HPCI SYSTEMS FOUND TO BE FUNCTIONAL-NO IMMEDIATE OPERABILITY CONCERNS.
TOTAL OF 34 OBSERVATIONS.
OBSERVED STRENGTHS:
" MAINTENANCE THAT WAS DONE, WAS DONE WELL.
-
THERE WAS EVIDENCE OF POST-MAINTENANCE TESTING AND VERY FEW EXAMPLES OF REPEAT MAINTENANCE. THIS REFLECTS A SKILLED MAINTENANCE STAFF WHO TAKE PRIDE IN THEIR WORK."
"THE SITE PERSONNEL WERE FOUND TO BE EXTREMELY
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KNOWLEDGEABLE, WHICH IS ATTRIBUTED TO A GOOD TRAINING PROGRAM AND A LOW EMPLOYEE
'
TURNOVER RATE."
"THE PLANT WAS FOUND TO BE RELATIVELY CLEAN,
-
WITH SIGNIFICANT ATTENTION PAID TO CLEANLINESS."
" LOGIC DIAGRAMS ARE CONTROLLED AS DESIGN
-
DOCUMENTS."
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EXAMPLES OF SSFl OBSERVATIONS ACCEPTANCE CRITERIA FOR THE STROKE TIME OF SAFETY RELATED VALVES EXCEED TIMES SPECIFIED IN THE FSAR AND EXCEED THE TIME REQUIREC FOR THE SYSTEM TO PERFORM !TS FUNCTION (WRB-7).
HEATING LAMPS INSTALLED BY A MAINTENANCE REQUEST TO KEEP THE HPCI TURBINE BEARING HOUSINGS WARM MAY I
NOT BE SEISMICALLY ANCHORED OR QUALIFIED TO l
WITHSTAND A SEISMIC DISTURBANCE (SMK-6)
THE CIRCUlT BREAKER AND RELAY SETPOINT SELECTION AND CONTROL HAS NOT BEEN ESTABLISHED (WGD-2).
THE EFFECTS OF REDUCED FLOW TO SAFETY RELATED
-
COMPONENTS IN THE SERVICE WATER SYSTEM RESULTING FROM LOSS OF AIR TO THE FAILED OPEN DIESEL GENERATOR COOLING WATER FLOW CONTROL VALVE HAVE NOT BEEN EVALUATED (SMK-4).
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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EXAMPLES OF SSFl OBSERVATIONS (cont.)
OPERATING PROCEDURE DOES NOT PROVIDE SUFFICIENT GUIDELINES TO OPERATORS FOR MANUALLY LOADING EMERGENCY DIESEL GENERATORS FOLLOWING A LOSS OF NORMAL POWER (LNP) OR A DEGRADED VOLT CONDITION (RLG-1).
UNCONTROLLED OPERATOR AIDS / LABELS ARE PRESENT IN THE CONTROL ROOM AND ON THE DIESEL GENERATOR A AND B LOCAL CONTROL PANELS (RLG-2).
THE SERVICE WATER FLOWS THROUGH THE EMERGENCY DIESEL GENERATORS ARE AFFECTED BY THE DIFFERENT BACK PRESSURES CREATED WHEN DIFFERENT DISCHARGE FLOW PATHS ARE USED. THE FLOW ACCEPTANCE CRITERIA ON THE DIESEL GENERATOR OPERATING DELA SHEET DOES NOT ACCOUNT FOR THIS VARIATION (RLG-4).
.
DESIGN WEAKNESS IN THE SENSING LINES FROM h M STANDBY DIESEL GENERATOR AIR START RECEI tRS TO THE PRESSURE SWITCHES THAT CONTROL THE AIR COMPRESSORS, AND IN THE LINES FROM THE RECEIVERS TO THE AIR START SYSTEM LOW PRESSURE ALARM (WRB-3).
.
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i SSFl INSPECTION MANHOUR ESTIMATE I
(NOT. INCLUSIVE OF MANHOURS SUBSEQUENT TO REPORT ISSUANCE TO RESOLVE OBSERVATIONS)
{
MAN-HOUR ESTIMATE ERCl/WESTEC MAN-HOURS.................................... 17 0 0 M-H R S,.
VY PLANT M AN-HO URS........................................... 1 5 0 0 M-H R S.
VY CORPORATE M AN-HOURS................................
5 0 0 M-H R S.
'
Y A EC M AN-HO URS.....................................................
7 0 0 M - H R S.
TOTAL VY SSFI MAN-HOUR ESTIMATE............... 4 4 0 0 M-HRS.
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