IR 05000271/1986018
| ML20211D671 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 10/10/1986 |
| From: | Elsasser T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20211D624 | List: |
| References | |
| 50-271-86-18, IEB-80-11, NUDOCS 8610220246 | |
| Download: ML20211D671 (16) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
86-18
Docket No.
50-271 License No. DPR-28
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i Licensee:
Vermont Yankee Nuclear Power Corporation RD 5, Box 169, Ferry Road Brattleboro, Vermont 05301 l
Facility:
Vermont Yankee Nuclear Power Station Location:
Vernon, Vermont
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Inspection Dates:
August 5 - September 3, 1986 Inspectors:
William J. Raymond, Senior Resident Inspector Thomas B. Sf1ko, Resident Inspector
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Greg Ne It, Resi ent pector (Hatch)
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Approved by:
L '/* w d AMC
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ad'6
ThomasC.Elsasser,(Chief,ReactorProjectsSection3C Date Inspection Summary:
Inspection on August 5 - September 3, 1986 (Report No.
50-271/86-18)
Areas Inspected:
Routine, unannounced inspection during day time and backshifts i
by the resident inspectors of:
actions on previous inspection findings; physical
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security; plant operations; licensee actions in response to GE RICSIL No. 7 con-cerning the adequacy of neutron monitor power supply failure detection circuits;
surveillance testing; maintenance activities; and, licensee actions to correct block wall discrepancies ( IE Bulletin 80-11).
The inspection involved 147 hours0.0017 days <br />0.0408 hours <br />2.430556e-4 weeks <br />5.59335e-5 months <br />.
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Results:
No violations were identified.
Operational status reviews identified no conditions adverse to plant safety.
Further licensee and NRC followup actions and reviews are warranted to assure block wall discrepancies and associated pro-
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grammatic issues are adequately addressed,(section 9.0).
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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 information pertinent to the areas inspected.
Inspection findings were discussed periodically with the management and supervisory personnel listed below.
Vermont Yankee Mr. J. DeVincentis, Engineer Mr. P. Donnelly, Maintenance Superintendent Mr. J. Pelletier, Plant Manager f4. T. Trask, Engineer M.. R. Wanczyk, Technical Services Superintendent Messrs. W. Raymond, P. Lohaus, and R. Bernero attended a meeting of the Ver-mont State Nuclear Advisory Panel on August 14, 1986 to discuss the plant restart ar.d recent NRC initiatives regarding the safety and potential im-provements that can be made to the BWR Mark I containment structure.
2.
Summary of Facility Activities The reactor operated at 100% full power during the inspection dates, except for periods of reduced power operations to support routine surveillance test-
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ing. Region I personnel conducted an inspection in the area of QA and non-licensed training on August 25-29, 1986.
Results of this inspection can be found in Inspection Report 86-20.
3.0 Status of Previous Inspection Findings 3.1 (Closed) Unresolved Item 86-10-11: Training Documentation.
The inspector reviewed the training documentation th1t confirmed the completion of the
"EOP Walkthrough" exercises by operators in the Shift Supervisor and Supervisory Control Room Operator positions prior to plant restart on June 30, 1986.
Plant management involvement in the assessment process was evident.
Plant management evaluated the operators tested in the exercises and determined that the operators were ready to implement the new E0Ps.
The inspector noted further that all licensed personnel com-pleted additional training on the E0Ps as part of the Requalification Program, Cycle 3, ending in mid-August, 1986.
This item is closed.
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3.2 (Closed) Unresolved Item 80-22-04: Completion of Work Under IE Bulletin 79-14.
The completion of licensee actions under IEB 79-14 and the seis-mic reanalysis program were reviewed by the NRC staff in inspections 85-04 and 86-12.
Actions taken in response to Confirmatory Action letter i
85-06 were also reviewed by the NRC staff and found acceptable.
The analyses and modifications completed under the seismic reanalysis program
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have. included consideration for base plate flexibility in support'evalu-ations and a minimum safety factor of 4 has been assured for anchor bolt loads.
Thus, the full requirements of IEB 79-02 have have been satisfied.
This item is closed.
3.3 (Closed) Follow Item 82-07-06: FeedwaterRegulatingValves(FRhs)Sur-veillance and Inspections.
The licensee changed procedure OP 5353 to require disassembly, inspection and cleaning of the electrical-to-pneumatic controller internals for feedwater regulating valves V6-12A and B.
The preventive maintenance is completed during the annual in-spections.
There have been no subsequent failures of the valves of the type that occurred on.FCV6-12A on April 24, 1982.
This item is closed.
3.4 (Closed) Unresolved Item 85-30-10: Secondary Containment Requirements During NES Cask Movement.
This item was open due to questions raised by the inspector regarding the appropriateness of the licensee's position on Technical Specification 3.7.C.1.d requirements while loading a NES-5 cask with irradiated materials frcm the spent fuel pool (SFP).
The lic-ensee's original intention was to load the cask in December,1985 during the recirculation pipe replacement outage at a time when Reactor Building (RB) integrity was not in effect.
The inspector noted that the licensee subsequently experienced difficulty in obtaining the NES-5 cask and the irradiated materials are still in storage in the SFP.
The irradiated materials will still have to be removed from the pool some time in the future, but this activity can now be done with RB integrity in effect.
Although there is still a question on the validity of the licensee's
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former position, the issue is now moot.
This item is closed.
3.5 (0 pen) Follow Item 84-01-01: TMI TAP Item II.K.3.18 - ADS Actuation Logic.
By letters dated May 15, 1981 and October 26, 1983, the licensee summar-ized his position as to why ADS logic modifications proposed by the BWR owners group would not be implemented.
By letters dated June 3, 1983, and October 7, 1985, NRC:NRR rejected the licensee's proposed resolution for the TMI item and requested the licensee to submit a plan and schedule to implement one of two NRC approved modifications.
The licensee re-sponded to the staff's request by letter FVY 85-109 dated November 22, 1985 and committed to install hardware modifications during the 1987 refueling outage pending the completion of PRA studies as part of the process to evaluate alternative modifications.
During a meeting with the Operations Support Manager on July 31, 1986, the licensee indicated that additional time may be required to complete the engineering evalu-ations, but that the scheduled implementation of modifications during the 1987 outage remained unchanged.
The licensee will submit his pro-posed plans to modify the ADS logic to NRR for review early in 1987.
This item remains open pending completion of the licensee's actions and subsequent review by the NRC.
3.6 (0 pen) Unresolved Item 86-10-02: Condensate Stoarge Tank (CST) Leakage Monitoring.
The inspector reviewed the licensee's ongoing leakage moni-toring results for the CST and noted that none of the data collected
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j during the month of August was indicative of additional tank leakage.
l This item will remain open pending completion of the licensee's long term corrective actions identified in reports 86-10 and 86-15.
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3.7 (0 pen) Unresolved Item 86-15-05: Recirculation Flow Oscillations.
The
inspector monitored both recirculation loop flows during the inspection period and reviewed the licensee's data collection and evaluation of system parameters.. The flow anomaly-on the A recirculation loop was
characterized as follows: (i) average amplitude of-flow change - 1%;
(ii) occurrence frequency - 6.5 events per hour; (iii) average event
duration - 2 to 4 minutes; (iv) range of event duration - 0.5 to 15 minutes; (v) time spent in higher flow mode - 23%; (vi) core flow change - 0.30-0.5Y; and (vii) APRM change - 0.2-0.3%.
The oscillations have not caused the plant to exceed operating fuel thermal or technical
specification limits.
I The oscillations appear to be limited to the A loop; however, flow spikes periodically occur on the 8 loop that may be early indications of the f
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onset of the flow anomaly in that loop as well.
A significant observa-tion during this' period was the apparent correlation between changes-in
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j the jet pump flow distribution and the A loop flow.
The flow through
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j the center jet pump on the A header decreases slightly, and the outer jet pump flows increase slightly, when the A loop enters the high flow
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mode.
The jet pump flow distribution reverses when the loop enters the lower flow mode.
The correlation between the loop and the jet pump-flow distribution presents strong evidence that the flow' anomaly is caused by the periodic formation and collapse of vortices in the arms of the t
j recirculation loop header, or bistable flow vortexing.
The General Electric Company completed a safety evaluation of this
phenomena at the Pilgrim Station, as reported in NDE-47_-0385.
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principle conclusion of the report is that the flow anomaly constituted
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no safety issue and created no significant inpact on the plant.
The
j inspector noted that the GE safety evaluation is currently under review by the NRC:NRR staff.
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The inspector compared the VY system data with those observed at the Pilgrim station, and noted that the VY parameters were bounded by or were
comparable to the parameters evaluated to be acceptable.
The major ex-ception to the above conclusion regarding the two data sets was for the
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parameter on the time spent in the high flow mode - 12% at Pilgrim versus 23% at VY.
However, this difference was not judged by the inspector to be significant in that the magnitude of the flow oscillations at VY are
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j less than one-half of the values at Pilgrim.
The inspector noted that the licensee's evaluation of the flow anomaly
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i was still in progress.
Reactor Engineering personnel expect to submit
an evaluation report and data package to GE for review and comment in September, 1986.
The licensee has made a preliminary determination that
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no procedure changes are warranted due to the limited magnitude of the
oscillations.
This item remains open pending completion of the licen-j see's and GE's evaluation, and subsequent review by the NRC.
4.0 Observations of Physical Security b
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Selected aspects of plant physical security were reviewed during regular and backshift hours to verify that controls were in accordance with the security
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plan and approved procedures.
This review included the following security j
measures: guard staffing; verification of physical barrier integrity in the protected and vital areas; verification that isolation zones were mahtained;
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i and implementation of access controls, including identification, authorization, badging, escorting,' personnel and vehicle searches.
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l 4.1 Security Events
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On August 22 and August 29, 1986, the licensee experienced a moderate loss of physical security effectiveness due to hardware failures within the central alarm station.
Both events were reported via the Emergency Notification System and written reports were submitted (Physical Security
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Event Report 86-03 and 86-04) per the time requirements specified by 10 CFR 73.71(c).
The inspector reviewed the circumstances involved in each event; compensatory actions taken; corrective actions to prevent the hardware failures; and, the content of the Physical Security event re-j ports.
No inadequacies were identified.
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5.0 Inspection Tours and Operational Status Reviews
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Plant tours were conducted routinely to observe operating activities in pro-i gress and to verify compliance with regulatory and administrative requirements.
j Tours of accessible plant areas included the control room, reactor building,
cable spreading and switchgear rooms, diesel rooms, and grounds within the protected area.
Radiation controls were reviewed to verify access control
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barriers, postings, and posted radiation levels were appropriate.
Plant
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housekeeping conditions were reviewed and found adequate. Shift logs and i
records were reviewed to determine the status of plant conditions and changes j
in operational status.
Items that received further review are discussed below.
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i 5.1 CST Chemistry Analysis
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The inspector witnessed the collection and analysis of drainage water
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from the base of the CST on 8/7/86, which was completed per OP 0631, Radiochemistry, Revision 6.
The tritium concentration in the drainage was 3.36X E-3 uCi/ml which was slightly less than the concentration in
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CST water.
The inspector witnessed the analysis and independently veri-
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fled the tritium calculation from the sample counting data.
No inade-
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quacies were identified, except as noted below.
The equation in Step 6 of OP 0631 for calculating tritium concentration t
based on output from the Beckman LS-100C counting system was in error
by specifying that the gross counts be divided by the total counting time e
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to obtain " counts per minutes".
The LS-100C provides the sample activity results in " counts per minute".
Laboratory technicians were familiar with the operation of the LS-100C and performed the calculation correctly.
The inspector also noted that Step 5.d of OP 0631 specified a " preset error selector" setting of 1%, which differed from the 0.2%. setting in use on the counting system.
The setting in use on the system was ac-ceptable and provided results that were equal to or better than those that would be obtained by using a 1% setting.
The inspector discussed the above procedure items with the Plant Chemist on August 7, 1986, who noted the discrepancies.
The Chemist stated that OP 0631 was presently in the review cycle and the errors would be cor-rected during the next procedure revision.
The inspector had no further comment on this item.
The overall quality and accuracy of plant procedures has been found to be acceptable during previous NRC inspections, and will be reviewed during subsequent routine inspections.
5.2 High Pressure Coolant Injection Outage During plant operations at 100% FP on August 18, 1986, plant operators declared the HPCI system inoperable at 3:50 P.M. due to an electrical ground on the DC supply for the gland condenser condensate pump.
Oper-ability testing was completed on alternate systems per technical speci-fication requirements.
The HQ: 00 was notified at 4:20 P.M. per 50.72(b)(2)(iii).
The licensee determined that condensation from the gland condenser exhaust blower was dripping on the condensate pump.
Maintenance personnel dried out the pump windings and diverted the con-densation drippage away from the pump.
The HPCI Condensate pump was tested satisfactorily and the HPCI system was returned to an operable status at 6:25 P.M. on 8/18/86.
The inspector reviewed the licensee's
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actions for this item and identified no inadequacies.
5.3 RCU Pump Seal Leak The mechanical seal on the A reactor water cleanup pump failed while operating at 6:45 P.M. on 8/15/86, resulting in elevated temperatures in the pump room, and minor leakages of radioactive steam and water on the 280 f t, elevation of the reactor building.
The reactor was operating at 100% FP steady state conditions at the time.
The seal failed after the shift auxiliary operator had noted excessive seal leakage, and while actions were in progress to switch cleanup system operation from the A to the B pump.
Plant operators isolated the cleanup system and depres-surized the piping by 6:50 p.m. to stop the leak.
The RCU system was returned to service with the B pump at 8:20 P.M. on August 15, 1986.
The resident inspector followed the licensee's cleanup and repair acti-vities, and reviewed the licensee's response to the event.
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The RCU room temperature increased to about 112 degrees F, which was about 10 degrees above normal but below the 125 degree F trip setpoint
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that would cause an automatic isolation of the reactor water cleanup sys tem'.
The cleanup pump room temperatures were not high enough to sig-
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i nificantly affect plant systems.
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Reactor coolant iodine levels at the time of the leak were about 1 X E-3
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UCi/gm, which was much less than the Technical Specification limit of 1.1 uCi/gm.
However, the leak did cause a slight increase in airborne activity in the reactor building, which went up slightly from the back-
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ground value of 1.0 E+4 CPM as measured on the building ventilation ef-fluent monitors.
Local airborne levels in the "A" RCU room at the time of the leak reached 3.02 E-8 uCi/cc, or 1.98 MPC(40), with Co-60 primary as the principal contributor at 1.57 MPC.
Radiation levels just outside the A RWCU pump room, as monitored by a local area radiation monitor, did not reach the monitor alarm setpoint of 20 mrem /hr.
Low level sur-face contamination was inadvertently tracked to other reactor building areas from the RCU pump room by workers who responded to isolate leak.
The maximum general area contamination in the reactor building was 10K-30K DPM/100 cm-sq measured on the floor area just outside the pump room.
Contamination levels inside the pump room were higher at 400K DPM/100 cm sq on the pump and floor.
Subsequent work and decon activities in the room were controlled by RWP.
There were no instances of personnel contamination.
Bady counts taken on August 16, 1986 for 10 workers who responded to the event showed no measurable uptake from the event.
Based on the above, the inspector determined that the onsite radiological im-pact of the event was minimal.
The failed seal and the resultant small leakage from the reactor coolant system did not create an operational problem to the reactor operator in the control of the plant.
The RWCU pump has a 2 inch outside diameter shaft that uses an Ingersol Rand Type 881 shaft seal.
The licensee de-termined that the shaft seal failed in such a way as to create a 0.023 inch circumferential gap (orifice) between the shaft and the tungsten carbide stationary seal ring.
The licensee estimated that the total reactor coolant. leakage through the failed seal was about 11 gpm.
Based on the above and the normal makeup supplies available to the reactor, the inspector concluded that the seal failure did not significantly affect plant safety.
Cleanup activities were completed to decon areas affected by the leak.
All plant areas outside the pump room were cleaned and open for general entry.
Efforts to decontaminate the A pump room were in progress at the end of the inspection period.
The RWCU pump rooms are contamination and high radiation areas during normal operations and entry to these rooms was controlled under radiation work permits.
The exact cause for the seal failure was not identified.
The inspector noted that the seal was installed in June, 1986 following a seal failure on the A pump during the vessel hydrostatic test.
The A pump seal was
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repaired and the A pump was subsequently returned to service.
The lic-ensee reviewed the event for reportability under 10 CFR 50.73 and con-cluded that none of the reporting criteria were met.
No inadequacies were identified.
5.4 Recirculation Loop A Flow Decrease Plant operators observed a downward trend in the A recirculation loop flow at approximately 5:30 a.m. on August 27, 1986, during plant opera-
tion at 100% full power.
The downward trend continued for approximately 15 minutes before leveling out, resulting in a core thermal power de-crease of 7 MWt.
The operators allowed the condition to exist for ap-proximately 1/2 an hour before increasing core flow by the use of the master / manual controller.
The controller adjustment resulted in the loop A flow increasing to its original amount plus the additional amount de-manded by the operator.
Loop B flow response to the increase in flow demand was normal.
Subsequently, 100% full power operation continued with both loops in normal operation.
MR 86-1923 was written to investigate the flow decrease.
The licensee determined that unlike the bistable flow anomalies (reference Inspection Report (IR) 86-15 and section 3.7 above), the flow decrease experience on August 27, 1986 was due to a control problem.
Further review revealed that dirty potentiometers in the recirculation flow controllers decreased in sensitivity to the point of allowing recirculation flow to decrease.
The poter,tiometers were cleaned and the system returned to normal on August 30, 1986.
The inspector identified no inadequacies.
5.5 Service Water Pump Operating Temperatures
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Motor winding temperatures for the A service water pump remained above the process computer alarm point during the first week of the inspection period, but below the operating temperature limit of 298 degress F (Reference Inspection Report 86-15, Section 6.1).
Inspector review of the operating temperature limit established by the licensee revealed an error in the licensee's calculations involving the converslun from de-grees Fahrenheit to degrees Celsius.
The maximum operating temperature according to NEMA Guidelines was recalculated by the licensee and deter-mined to be 266 degrees F.
The motor winding temperatures exceeded 266 degrees F by less than 5 degrees when ambient air temperatures increased significantly on hot days.
Pump operation with winding temperatures
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above 266 degrees F did not have an immediate adverse effect on the motor, but could reduce the life expectancy of the motor windings.
Mechanical bypass86-034 was implemented to provide local cooling to the
service water motor, which decreased winding temperatures below 266 de-j grees F.
The mechanical bypass and associated safety evaluation were
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reviewed by the inspector and found acceptable.
With Fall weather ap-proaching and the onset of cooler ambient average air temperatures, the winding temperature of the A service water motor will decrease accord-l
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The inspector noted that with the installed mechanical bypass and lower ambient air temperature, the overheating of the service water motor windings was no longer a concern.
The inspector had no further questions.
5.6 Diesel Generator Trip Diesel Generator (DG) A tripped during the monthly 8-hour surveillance test at 11:10 p.m. on August 5, 1986, due to an apparent voltage dis-turbance on the offsite grid.
Following consultation with the load dis-patcher, DG A was restarted at 11:50 p.m., and subsequently completed i
a successful surveillance test run.
Inspector discussions with the Operations and the Maintenance Supervisors verified that the DG responded properly and that the trip was not caused by a failure within the DG protective relaying.
No inadequacies were identified.
5.7 Torus Vacuum Relief System The inspector received information from NRC: Region I on August 8, 1986 concerning a potential problem with the torus vacuum relief system iden-tified at another facility.
The problem concerned a reversal in the control logic for the reactor building to torus vacuum valves, which would have caused the valves to isolate on a negative pressure condition in the torus and thereby defeat the safety function.
The logic problem was caused by a reversal in instrument sensing lines from the torus to the differential pressure transmitter used in the vacuum breaker controls.
The inspector completed a walkdown of the sensing lines for torus dif-ferential pressure instrument 16-19-31A and B, reviewed the technical manuals for ITT Barton Model 288A and 289A instruments, and interviewed I&C personnel.
Additionally, the licensee performed a functional test of instrument 16-19-31A on August 18, 1986 at the request of the inspec-tor.
This review determined that the instruments at Vermont Yankee were properly installed and would operate correctly to protect the torus from excessive negative pressures.
No inadequacies were identified.
5.8 Recirculation Pump Alarms A high vibration alarm occurred on the B recirculation pump at 11:00 a.m.
on August 19, 1986, which irdicated pump vibration was in excess of 3 mils.
There is no remote vibration indication available to the control room.
Following an evaluation of the alarm and the pump conditions, the licensee shut down the pump and noted that the alarm stayed in.
The alarm was thus determined to be invalid.
The B recirculation pump was restarted at 5:00 p.m. and power operations resumed.
At 8:30 p.m. on August 19, 1986, a high/ low lube oil level alarm was received on the B recirculation pump and the pump was shutdown for further investigation.
A decision was made to shutdown the plant, de-inert, and enter the dry-well to inspect the pump conditions.
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During a drywell entry at 5:00 a.m. on August 20, 1986, the licensee determined that the pump conditions were satisfactory and that the lube oil and vibration indications were faulty.
Attempts to restore the in-
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dications to an operable status were successful at first, but after con-tinued difficulties were experienced with the alarm circuits, subsequent plant operation was resumed with the alarm circuits for vibration and high' lube oil level bypassed.
The cause for the alarm circuit problems
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was not resolved and the licensee plans to investigate and repair the circuits during a subsequent outage.
The inspector noted that other pump performance indicators are available
in the control room to alert the operators to adverse pump conditions that otherwise would be annunciated by the affected circuits.
The loss of one recirculation pump is an operational transient that was analyzed
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in the FSAR (Section 14.5.5.2) and found acceptable, since no safety -
concerns for plant workers or equipment would be created.
Thus, con '
tinued plant operation without the recirculation pump alarm circuits constitutes only a power generation risk.
No inadequacies were identi-fied.
5. 9 RWCU Valve V12-68 failure Maintenance personnel tightened the packing on reactor water cleanup (RWCU) system discharge isolation valve, V12-68, per MR 86-1891 on August 29, 1986 in an attempt to eliminate apparent packing leakage.
The gland adjustment nut was turned several times and the packing became bound to the valve stem.
The actual source of leakage 'was from the bon-net seating surface on the valve which was not properli torqued to the valve body, and additionally was missing a cap screw that would normally
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secure the bonnet assembly.
The loose bonnet assembly was not noted by maintenance personnel. During post-adjustment stroke timing of the valve, the motor operator turned the bonnet assembly about one-half turn until'
the valve motor burned out, causing a significant steam leak past the
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bonnet seating surface.
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The bonnet seal on V68 failed at 2:45 p.m. on August '2),1986, which caused the leakage of radioactive steam into the RWCU pump area on the 280 ft elevation of the Reactor Building.
Plant operators immediately isolated the RWCU system by closing pump suction valves V15 and V18, and by closing manual valve V63 on the RWCU system return line. The operators opened condenser blowdown valve V74 to depressurize the RWCU system and thereby stop the leakage into the reactor building.
Plant operators re e aligned the control rod drive system return flow per OP 2111, which was also isolated when the RWCU system was secured.
Adequate control rod drive cooling and accumulator charging pressures were maintained while the cleanup system remained isolated.
The operators also switched the cleanup conductivity monitor to take suction from the recirculation sys-tem to provide an accurate online monitor of the trend in vessel chemis-try with the RWCU system isolated.
Reactor conductivity levels remained
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I below the technical specification limit of 5 umhos/cm during the RWCU j
system outage.
The inspector reviewed the operator's actions in response i
to the event and identified no inadequacies.
The RWCU pump area airborne'radioactivty showed levels of 3.2X E-9 uCi/cc at 3:05 p.m.
Respiratory protection would normally be used for extended work in areas at that concentration, but plant operators evacuated the Reactor Building at 3:05 p.m., and area levels decreased to 2.8 X E-10 uCi/cc by 4:13 p.m.
Reactor coolant iodine levels at the time of the leak were about 9 X E-4 uCi/gm, which was well below the technical spect-s fication limit of 1.1 uCi/gm.
The inspector reviewed area and stack radiation monitors for the event and noted that only the Reactor Building ventilation' particulate monitor showed an increase, from 2500 counts per
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Based on the above, the inspector determined that the onsite radiological impact from the event was minimal.
RWCU valve V68 is a motor operated globe valve that receives a primary containment group 5 (RWCU system only) isolation signal and is required by Technical Specification Table 4.2.7.a to be operable during reactor operation at power.
No isolation valve redundant to V68 in the RWCU return line is identified in the technical specifications.
Howeve.*, the RWCU return line discharges into the B feedwater line, and the following valves associated with primary containment penetration X-9B would provide automatic isolation for pipe break protection: feedwater check valve 28B, j
feedwater check valve 96A, RWCU check valve 62, and RWCU check valve 62A.
Valve 96A is locally leak rate tested as part of the licensee's 10 CFR 50 Appendix J test program.
Additionally, the manual RWCU valve V63, a split disc gate valve, is leak tested in the reverse direction as part of the test isolation boundary for V68.
The licensee stated further that, based on the current Appendix J exemption request submitted for NRC re-view by letters WVY 80-132 and FVY 81-148, and accepted by the staff in an SER dated 8/19/83, the cleanup V68 valve is no longer considered to be a primary containment isolation valve, and testing requirements for the valve will be deleted from technical specifications during the next issuance of Table 4.7.2.a.
The licensee stated that the apparent origi-nal need to designate V68 as an isolation valve stemmed from.an early reactor design which included a separate vessel penetration for the RWCU return piping.
The above bases for the technical specifications and the licensee's pro-posed corrective actions were discussed in a telephone conversation with the NRC Region I staff on August 29, 1986.
Based on the above technical data and the multiple isolation valves for penetration X98, it was de-termined that plant operation with V68 inoperable as a containment isolation valve was an acceptable condition. -This situation did not con-stitute a safety problem, but rather an interpretation problem in comply-
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ing with Technical Specification 3.7.D.1.
The licensee proposed isolating the RWCU system and completing repairs on V68 in an expeditious manner, and doing so without entering the technical specification action statc-
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4 ment. The inspector accepted the licensee's proposed course of action.
The licensee's maintenance activities were inspected on August 30, 1986 ar.d the progress of the work effort was reviewed during the period of Auaust 30-September 1, 1986.
Mechanical bypass 86-0036 was implemented on August 30, 1986 to allow installation of blind flanges at RWCU system spool pieces, and thereby allow partial RWCU system operat10n for chemistry control, and further to allow opening of the reactor water cleanup system and repair of V68 during reactor operation. The inspector reviewed the mechanical bypass and associated safety evaluation and identified no inadequacies.
Main-tenance personnel replaced the' internals of V68 and relapped the bonnet seat.
The motor operator was ' replaced.
The valve was satisfactorily cycled following repairs and a Type C leakage rate test was satisfactorily completed to verify the integrity of the repaired bonnet seat.
The reactor water cleanup system was returned to service at 3:00 a.m. on September 1, 1986 following completion of testing and restoration of the mechanical bypass.
Future routine inspection will consider maintenance and technical specification aspects of this matter.
No violations were identified.
6.0 IntermediateMangeMonitors'(IRM)PowerSupplies Based on a General Electric (GE) Rapid Information Communication Services -In-formation Letter (RICSIL) Number 007, the licensee was investigating a pos-sible failure mode of the neutron intermediate range monitors (IRMs) that may
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not be detectable and may not provide the reactor protection systcm scram during -startup.
Loss of the IRM negative power supply voltage would not cause an inoperable IRM trip card light and would result in a signal output from the amp.lifier, which uses the negative power supply, to be above the downscale trip and below the upscale trip regardless of the actual neutron flux levels.
GE is examining a relay / contact modification which would monitor the IRM negative power supply and would initiate an 'inopsrable trip light if a loss of power occurs.
The results of GE's final recommendation will be provided in a GE Services Information Letter.
The licensee upgraded his tracking
' identification classification of RICSIL-007 from a Category "B1 to a Category
"A" item based on station procedure AP 0028 and the inspector's' comments.
Also, this concern will be addressed in the standing order book to alert operators of the possible IRM failure' mode.
The unit is currently at full power and no IRM testing is planned until the unit is shutdown. The 24 vdc neutron monitoring power supply system is presently fully operable.
7.'O'
Surveillance Testing The inspector reviewed portions of the surveillance tests listed below to verify that testing was performed in accordance with administrative require-ments.
The rev'iew included consideration of the following: procedures tech-
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nically adequate; testing performed by qualified personnel; test data demon-strated conformance with technical specification requirements; test data anomalies appropriately resolved; surveillance schedules met; test results reviewed and approved by supervisory personnel; and, proper restoration of systems to service.
OPF 4310.01 Scram discharge instrument valve (SDIV) Hi water level
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functional data sheet, conducted August 27, 1986 OPF 4310.02 SDIV hi water level calibration data sheet, conducted
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August 27, 1986
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OP 4376 Torus-Reactor Building Vacuum Breaker Differential Pres-sure Test, DPIS 16-19-32A, conducted on August 18, 1986 OP 4020 Fire Protection System Surveillance, inspected August 15,
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1986 The OP 4310 test results were reviewed following the replacement of the SDIV level transmitter power supply.
The inspector reviewed the test methodology in OP 4376 and verified the procedure was technically adequate.
No inade-quacies were identified.
8.0 Maintenance Activities The maintenance request log was reviewed to determine the scope and nature of work done on safety related equipment.
The review confirmed: the repair of safety related equipment received priority attention; technical specifica-tion limiting conditions for operation were met while components were out of service; performance of alternate safety related systems was not impaired; and, the maintenance activity did not create an unreviewed safety question.
Maintenance activity associated with the following was reviewed to verify (where mplicable) procedure compliance and equipment return to service, in-cluding operability testing.
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MR 86-1855 Repair RCIC Fire Protection deluge Valve DV-301 which failed to open during. surveillance test OP 4020.17 MR 86-1879 Repair Leaking RHRSW associated valve SE-70-4D
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No inadequacies were identified.
Items requiring further followup are dis-cussed below.
8.1 Fire Protection Deluge Valve DV-301 Fire protection deluge valve DV-301 did not open as required during annual testing per OP 4020 on August 15, 1986.
Failure of DV-301 to open
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i upon demand rendered the Reactor Building 232 and 252 ft. elevation l
penetration area pre-action sprinkler system inoperable, which was con-
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trary to the 'requirenents of Technical Specification 3.13.F.
Licensee investigation of the valve internals determined that a small amount of corrosion and/or river silt deposited in the latch-flapper area caused the valve to remain shut against 100 psi fire system pressure when acti-vated during the test.
Actions were completed to clean the valve in-ternals, reassemble and successfully retest the valve manual and auto-matic actuation features.
The inspector reviewed the licensee's investigation of the problem to verify the root cause of the failure was identified and corrected.
DV-301 is an Automatic Sprinkler Corporation Model "D" Pre-action valve.
The licensee stated that DV-301 is the only valve of its type in use at the site.
Licensee followup actions were in progress at the conclusion of the inspection to obtain further information from the valve vendor regarding methods to lubricate the valve internals.
The licensee also stated the valve failure would be reviewed for,reportability, and that act1ons would be taken to increase the valve test frequency to once per month until a permanent solution to the problem is in place, or a longer test frequency is otherwise proven acceptable.
This item is unresolved pending completion of the licensee's actions listed above, and subsequent review by the-NRC (UNR 86-18-01).
9.0 Degraded Block Walls The licensee informed the inspector at 3:00 p.m. on September 2, 1986 of a discrepancy that was identified regarding certain block walls at the site.
The licensee was notified on September 2, 1986 by Yankee Atomic Electric Com-pany (YAEC) of discrepancies identified by YAEC Engineering as part of a self-
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audit conducted in preparation for the NRC inspection planned for the week of September 9, 1986 to evaluate licensee response to IE Bulletin 80-11.
The discrepancies occurred as a result of the informal manner in which a block wall survey was conpleted by YAEC in 1980 to address IE Bulletin 80-11 issues.
A resurvey of_the block walls at Vermont Yankee completed by YAEC in 1986 reconfirmed the basic validity and adequacy.uf the 1980 survey, in that 111 of 115 walls reviewed were acceptable.
However, 4 walls were found unaccept-able and could adversely impact equipment important to safety, as described
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below.
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The deficiency concerned unqualified and unrestrained block walls in the Tur-bine Building ventilation corridor that could fail during a seismic event and potentially adversely affect the following plant electrical circuits and systems:
(i) Cables for all 4 main steam line radiation monitors that provide trip inputs (main steam line radiation levels 3X normal background) for the reactor protection system and the primary containment isolation system.
Loss of the trip input to the RPS would be backed up by other system parpameters reaching trip setpoints.
There would be no backup trip in-iti'ator to assure the main steam lines isolate in the event of a dropped rod accident.
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(ii) Control cables for the four reactor recirculation units, RRU 5, 6, 7,
& 8, in the ECCS corner rooms in the reactor building.
The RRUs are normally in standby and receive a start signal when equipment in the respective rooms are in service. The are RRUs required to be operable to control corner room environmental conditions and thereby assure ECCS equipment long term operability. requirements.
Assuming the resctor building is accessible following a seismic event, the licensee stated that actions could be taken locally to start the RRUs.
(iii) Control cables for the fans in the A and B diesel rooms.
The diesel room fans are required to operate during diesel generator operation to main-tain room environmental conditions acceptable.
The licensee stated that actions could be taken following a seismic event to start the fans locally and/or otherwise provide for room cooling.
(iv) Service Building Air Conditioning (SAC) Unit IA and associated duct work.
SAC 1A is part of the normal and emergency heating and ventilation system for the main control room. Failure of.a block wall adjacent to SAC 1A could affect the unit control circuits and damage a portion of the fresh air intake and closed circuit recirculation ducting for the control room HVAC.
The licensee stated that upon failure of the SAC 1A unit, actions could be taken locally to provide for cooling in the control room.
The licensee stated further that irrespective of the damage that a failed block wall may cause to SAC 1A, the remainder of the control room HVAC, even though.it is safety class 3, it is not seismically qualified.
The control room HVAC was installed as non nuclear safety during the initial
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plant design and was upgraded to safety class 3 during the late 1970's to assure repair and modification of the system would be subjected to the cuality assurance program.
The licensee stated that protection of the control room environment for a concurrent seismic event, LOCA and degraded core (TMI type source term) condition was beyond the design basis for the plant.
The licensee stated that an engineering evaluation'to address the above items would be submitted for NRC staff review that would provide a justification for continued operation pending completion of actions to correct the block wall deficiencies.
The licensee stated that modifications to either relocate control cables or to support block walls would be completed as necessary to address inadequacies in each of the above four areas.
The required modifica-tions would be completed potentially as early as November, 1986, and in any case, no later than the end of 1986, The inspector requested that the.licen-see address his engineering evaluation, proposed fixes and modification schedule in a letter to NRC Region I.
The licensee stated the letter would be submitted by September 12, 1986.
The inspector noted that all of the above identified equipment was presently operable and capable of performing the intended safety functions.
Based on the above, the inspector determined that the plant is currently operating in accordance with the license conditions, and continued plant operation is
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therefore acceptable.
The inspector noted further that the licensee proposed to correct the identified deficiencies in a timely manner and to formally address the justification for interim operation to the NRC.
The adequacy of the licensee's evaluations will be reviewed by the NRC staff as part of In-spection 86-22.
The licensee is also reviewing the item for reportability under 10 CFR 50.73.
The inspector noted further that a team inspection by NRC Regional and con-tractor personnel was planned during the period of September 9-12, 1986 (In-spection 86-17) to review the adequacy of the licensees actions under IEB 80-11.
Inspection 86-17 will also address the adequacy of the licensee's programmatic controls that allowed the aforementioned deficiencies to occur, and will determine what, if any, enforcement actions by the NRC may be appro-priate.
This-item is unresolved pending completion of the licensee's actions noted above to assess, report and correct the identified discrepancies, and pending NRC staff review of the licensee's actions under IEB 80-11 (UNR 86-02).
10.0 Management Meetings Preliminary inspection findings were discussed with licensee management peri-odically during the inspection.
A summary of findings for the report period was also discussed at the conclusion of the inspection and prior to report issuance.
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