IR 05000271/1985014
| ML20126C409 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 05/03/1985 |
| From: | Raymond W, Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20126C389 | List: |
| References | |
| 50-271-85-14, IEB-84-01, IEB-84-1, NUDOCS 8506140411 | |
| Download: ML20126C409 (19) | |
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U. S. NUCLEAR _ REGULATORY CONNISSION
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REGION I
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' Report No.
85-14
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Docket No.
50-271 License No. DPR-28
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Licensee:
Vennont Yankee Nuclear Power Corporation RD 5, Box 169 Ferry Road Brattleboro, Vermont 05301 Facility Name: Vennont Yankee Nuclear Power Station Inspection at: Vernon, Vennont Inspection Conducted: April 2 - May 6,1985
//$ ret M
[3 7 Inspectors:
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W.J.Raymond,SeporRespentInspector
!A Mid
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Approved by:
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E. E. Triff, Chief, Reactor Projects Hate
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Section 3A, Projects Branch 3
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Inspection Sumary: Inspection on Aprii 2 - May 6,.1985 (Report No. 50-271/85-14)
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Areas Inspected: Routine,' unannounced inspection on day time and backshifts by the resident inspector of: actions on previous inspection findings; plant power i
operations, including operating activities.and records; plant physical security; l
surveillance testing; maintenance activities; staffing changes; LER review; review l
of the 1985 Emergency Preparedness exercise; and, followup of actions on IE Bulletin l
~ 84-01 and GE SIL #402, Cracks in BWR Mark I Containment Vent Headers. -The inspection l
involved 125 hours0.00145 days <br />0.0347 hours <br />2.066799e-4 weeks <br />4.75625e-5 months <br />.
Results: No violations were identified in.9 areas inspected. Operational status reviews identified no conditions adverse to safe operation of the facility. Two
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items that warrant further review to assure compliance with the technical specifica-tions concern the APRM operability definition for LPRM inputs (paragraph 2.0), and, the completion of alternate surveillance testing when a diesel generator is out of service (paragraph 9.0).
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DETAILS
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Persons Contacted
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Interviews and discussions were conducted with members of 'the licensee staff and
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. management during the report period to obtain information pertinent to the areas inspected.
Inspection findings were discus ~ sed periodically with the' personnel listed below.
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Mr. D. Reid, Operations Superintendent Mr. J. Pelletier, Plant Manager
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Status of Previous-Inspection Findings 2.1 (0 pen)UnresolvedItem 85-10-02: APRM Testing'and Operability Requirements.
OP 2132 is an Operations Department procedure that provides instructions on how to operate and align the APRMs for normal operations. Procedure section A.1 provides instructions on the performance of an APRM front panel functional check, including a check of the LPRM input counting circuitry.
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- Procedure steps A.1.e and f instruct the operator to bypass LPRMs until the maximum permissible number of inoperable inputs plus one has been bypassed, and then verify that the counting circuitry initiates an inoperable trip of the APRM channel.
Pro-cedure step e requires that 9 LPRM channels be bypassed for APRM channels B or E, and 13 LPRM channels be bypassed for APRM channels A, C, D or F.
There.are 20 LPRM inputs in each of the six APRM channels. APRM channels A and D, and C and F are companion channels, each having 10 LPRM inputs that are shared for a total of 20.
The inference from procedure step e is that APRM channels B and E must have (20-9+1)*
12 inputs-to be operable, cnd APRM channels A, C, D, and F must have (20-13+1)=8
inputs to be operable.
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' The APRM operability requirement provided in Note 5 to Table 3.1.1 states..."To be i
considered operable an APRM must have at least 2 LPRM inputs per level and at l
1 east a total of 13 LPRM inputs, except that channels A, C, D and F may lose all LPRM inputs from the companion APRM cabinet plus one additional LPRM input and still be considered operable". Based on the above, it appears that Technical Specification 3.1.1 requires a minimum of 13 inputs for APRM channels B and E, and 9 inputs for APRM channels A, C, D and F, for operability, and thus, OP 2132 does l
not provide a proper test of the APRM counting circuit. This matter was discussed with the Operations Supervisor on April 9,1985, who stated that OP 2132 would be reviewed and corrected as applicable.
A second issue raised on this matter comes from an alternate.and equally acceptable reading of the technical specification operability requirement.
It appears that the specification could also require that each of the six APRM channels normally
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have at.least '13 LPRM inputs to be considered operable. An exception to the 13 input requirement is specifically allowed for channels A, C, D, and F, which can
lose all ten companion inputs plus one additional input and still be considered operable.
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The inference from the above reading of the. specification is that the 10 plus 1
' distribution of lost LPRM inputs is exclusive, and no other combination of lost inputs that result in less than 13 operable inputs (e.g., 3 from the companion
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channel plus 8) is allowed. The rationale for allowing a single exception to
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the 13 LPRM input requirement would stem from a provision to allow the loss of
a single RPS MG set, which would cause the loss of all 10 inputs to either APRM
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channels A and C, or D and F, depending on which power supply was affected.. If this -is the case, then the current LPRM counting circuits should be left as is,
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l and administrative procedures should be used to control the LPRM input distribu-F tion used to satisfy APRM operability requirements.
The inspector noted that the present number of operable-LPRM inputs to the 6 APRM channels far exceeds the minimum number required for operability, regardless of which rendering of the technical specification is used.
The correct reading of Technical Specification 3.1.1 regarding APRM operability requirements is a matter requiring further~ review by the licensee and NRC manage-ment to determine the minimum number of LPRM inputs required to consider an APRM operable.- This item remains unresolved pending completion 'of the licensee's review and subsequent review by the inspector.
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2.2 (Closed)UnresolvedItem 83-01-08: Corrective Actions ifor Containment Isolation Valves (CIVs) on the Drywell Nitrogen Purge Makeup Line. Supplement 1 to PDCR 82-02 was implemented prior to thelstartup from the 1983 refueling outage to upgrade CIVs VG 16-20-20.16-20-22A and.16-20-22B. -The existing Atkomatic valves were replaced with Target Rock Model 1025010-5415 valves, which are not subject to the same failure mechanism. No similar problems were; subsequently experienced with the purge line isolation valves. This item is closed.
2.3 (Closed)FollowItem 83-09-02: SB16-19-9OperabilityTesting. The air operator for the drywell air purge supply valve was repaired under MR 83-396 and operated manually. The valve automatic /PCIS control circuits were subsequently tested on May 26,1983 per OP 4334 prior to startup from the refueling outage on June 17, 1983. The inspector reviewed the test results and the valve control circuits per Drawing G191301, Sheets 1112 and 1113. This review showed that.
valve operability was satisfactorily demonstrated prior to its return to service.
This item is closed.
2.4 (Closed)FollowItem 80-02-02:
Environmental Qualification for Safety Valve Position Indication. The inspector reyjewed the design changes completed under PDCR 83-07 during the 1984 refueling outage to upgrade the B+W Acoustic Accelero-meter Valve Status Monitoring System on the safety valves to meet environmental qualification (EQ) requirements. The only system component lacking EQ was the charge converter, which transmits the-signal from the transducer to the control modu'e in the control room. The B+W charge converters were replaced with con-
- verters supplied by the Technology for Energy Corporation, which are qualified for the application. This item is close..
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2.5 (0 pen)UnresolvedItem 85-10-01:
Fuel Oil Storage Tank (FOST) Drain Line Evaluation. - The licensee cleaned the rust off the FOST drain line to inspect the piping segment between the tank and valve FO-6. The results of the visual and ultrasonic examinations were documented in an NSD evaluation memo dated April 3, 1985.
Extensive pit corrosion was noted over a 1.5 foot section of the two inch diameter,. schedule 80, carbon steel line. Most pits were measured to be in the range of 0.030 to 0.050 inches deep, with a miximum pit depth of 0.075
' inches.' Overall general corrosion in the pitted area caused some general wall
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thinning, which was estimated to be 10% or less of the pipe wall. UT measure-ment of the non-pitted-section of the pipe showed the wall thickness to be at or-near minimum value of 0.218 inches, with readings in the range of 0.208 to 0.225 inches. The minimum wall thickness in the corroded area was estimated to be no less than 0.123' inches.
The site Engineering Group completed an evaluation of the stresses the line could
'be subjected to under normal design and anticipated seismic loadings. This analysis showed that even with a 0.123 inch wall thickness. the, drain line was capable of operating during a seismic event.within the stress limits allowed by the ANSI B31.1 Piping code. The inspector, reviewed both!the minimum wall thick-ness and seismic stress calculations and. identified no inadequacies.
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The pipe section was painted under Maintenance Request 85-0568 to retard ~f rther corrosion pending completion of long term corrective action:to repair the line.'
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The repair will be completed during the upcoming refueling outage since any repair method will require that the line and FOST be drained. The 111censee will i
also review other piping attached to the FOST for corrosion and-take corrective
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actions, as required. The inspector. reviewed piping in the area and noted no
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problems. This item remains open pending completion of licensee actions to formu-late a long term corrective action plan and subsequent review by the.NRC.
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3.0 Observations of Physical Security
Selected aspects of plant physical security were reviewed during regular and back-
shift hours to verify that controls were in accordance with the security plan and
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approved procedures. This review included the following security measures:
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L staffing; random observations of the secondary alarm station; verification of i-physical barrier integrity in the protected and vital areas; verification that isolation zones were maintained; and implementation of access controls, including identification, authorization, badging, escorting, personnel and vehicle searches.
.The inspector reviewed the circumstances involved in the malfunction of security
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equipment at 1:47 A.M. on April 9, 1985, and at 10:50 A.M. on April 29, 1985, along with the compensatory measures taken by the guard force during the degraded l,
period. Compensatory measures were acceptable. A telephone notification was made j
to the NRC Duty Officer in accordance with 10 CFR 50.72. No inadequacies were
identified, i
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4.0 Shift Logs and Operating Records
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Shift logs and operating records were reviewed to detemine the status of the plant and changes in operational conditions since the'1ast log review, and to i
verify that:
(1) selected Technical Specification limits.were met;.(2) log'
entries involving abnomal conditions provided sufficient detail to communicate
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equipment status, correction, and restoration; (3) operating logs and surveillance -
sheets were properly completed and log book reviews were conducted by the staff; and,-(4) Operating and Special Orders did not conflict with Technical Specifica-
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tion requirements.
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The following plant logs and operating records were reviewed periodically during the period of April 2 - May 6,1985:
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Shift Supervisor's Log
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Night Order Book
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Control Room Operator Log
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Jumper / Lifted Lead Log
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Shift Turnover Checklists
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Radiochemistry Analysis Log
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-- Core Performance Typer-Log No unacceptable conditions were identified. The following items warranted inspector followup.
4.1 A Night Order Book entry on April 1,1985 concerned an error in Table 3.9.2 of the Radiological Effluent Technical Specifications, which were issued as Amendment 83 and became effective on April 1, 1985. Notes 2 and 5 of Table 3.9.2 specified the operability requirements and action statements for the two stack gas monitors, and were found to be in error by the licensee after Amendment 83 was
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issued. A memorandum from the Operations Supervisor dated March 21, 1985 clarified the intended operability recuirements for the monitors and instructed shift personnel on what actions shoult be taken when the monitors are inoperable.
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The clarification will remain in effect until the table notes are corrected by a subsequent amendment. The inspector reviewed the clarification and found it i
to be consistent with the fomer operability requirements. No inadequacies were identified.
4.2 An entry in the Shift Supervisors log on April 18, 1985 indicated that the Ames Hill NOAA radio transmitter was detemined to be inoperable at 5:39 A.M. by the contractor responsible for maintenance of the system. Shift personnel notified the NRC Duty Officer at 5:51 A.M. as required by 10 CFR 50.72 and AP 0156.
l The Ames Hill station was returned to an operable status at 7:10 A.M. on April 18, 1985.
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I The Ames Hill transmitter (located in. Marlboro, Vemont)
is the inter-I mediate transmission link in the Public Notification system signal originating I
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at Mount Ascutney and would be used to activate tone alert radios for an emergency at both the Vermont Yankee and Yankee sites. Both the primary and backup transmission channels at the Ames Hill station failed. Radio Station WTSA transmission equipment is a backup for the Mount Ascutney station and was unaffected.
No inadequacies were identified.
5.0 Inspection Tours Plant tours were conducted routinely during the inspection period to observe activities in progress and verify compliance with regulatory and administrative requirements. Tours of accessible plant areas included the Control Room Building, Reactor Building. Turbine Building, Diesel Rooms, Control Point Areas and the grounds within the Protected Area. Control room staffing was reviewed for conformance with the requirements of the technical specifications and AP 0036, Shift Staffing.
Inspection reviews and findings completed during the tours were as described below.
5.1 Systems and equipment in all areas toured were observed for the existence of fluid leaks and abnormal piping vibrations. Pipe hangers and restraints in-stalled on various piping systems were observed for proper installation and condition. No inadequacies were identified.
5.2 Plant Housekeeping conditions, including general cleanliness and storage of materials to prevent fire hazards were observed in all areas toured for con-fonnance with AP 0042, Plant Fire Prevention. No inadequacies were identified.
5.3 The inspector monitored the feedwater sparger leakage detection system data and reviewed the monthly sumary of feedwater sparger performance provided by the licensee in accordance with his comitment to NRC:NRR made in letter FVY 82-105. The licensee reported that, based on the leakage monitoring data reduced as of March 31, 1985, there were (1) no deviations in excess of 0.10 from the steady state value of normalized thermocouple readings; and (2) no failures in the 16 thermocouples initially installed on the 4 feedwater nozzles. No unacceptable conditions were identified.
5.4 Analysis results from samples of process liquids and gases were reviewed periodically during the inspection to verify confonnance with regulatory require-ments. The results of isotopic analyses of radwaste, reactor coolant, off-gas and stack samples recorded in shift logs and the Plant Daily Status were re-viewed. Sample results for the standby liquid control tank on April 5,1985 showed that the boron concentration was maintained within technical specifica-tion limits. No inadequacies were identified. The inspector had no further coment in this area, except as noted below.
5.4.1 Following the completion of routine and additional control rod surveil-lance testing at 80% full power on April 28, 1985, plant operators noted a slight
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7 increase in the offgas radiation channels. Offgas channel' 7-150' A (black pen) increased from a normal reading of 21 mrem /hr to 28 mrem /hr. Offgas
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channel 17-150B showed the same trend as the_ A channel but at a lower magnitude.
There was no change measured by the more sensitive linear offga's channel 17-154.
The stack gas monitors also showed a slight increase in radiation levels with a maximum release rate of less than 200 uC1/sec. This valve was much less than the established release limits. The discharge path would be the steam packing exhaust from the tGrbine sealing system, which bypasses the advanced offgas
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system. The stack channels returned to background levels that existed prior
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to the control rod tests.
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Chemistry and Health Physics technicians analyzed an offgas sample taken at 7:25 A.M. and noted normal release rates at about 800 uC1/sec.
No inadequacies were identified in the plant personnel response to the indications.
5.5 The status of the Residual Heat Removal (RHR), RHR Service Water, Standby Gas Treatment System, High Pressure Coolant Injection, Standby Liquid Control, Core Spray, Diesel Generators, and Reactor Core Isolation Cooling (RCIC) systems was reviewed to verify that the systems were properly aligned and fully operational in the standby mode. The review included the following:
(1) verification that each accessible, major flow path valve was correctly positioned; (2) verification that power supplies and electrical breakers were properly aligned for active components; and, (3) visual inspection of major components for leakage, proper lubrication, cooling water supply, and general condition. All of the above safety systems were found fully operable during the inspection period. The item below warranted further inspector followup.
5.5.1 During a routine review of the control panels at 10:00 A.M. on April 25, 1985, the inspector noted that the minimum flow valve V10-16B for RHR pumps B and D was open instead of shut as required by OP 2124. The item was discussed with the supervisory control room operator, who closed the valve. The inspector interviewed control room personnel regarding the status of the valve. Both operators had noted that the valve was closed during the 8:00 A.M. shift turnover checks. There was no testing or other activity in progress that would explain how the valve was opened.
The minimum flow valve is normally closed when the RHR system is in the standby status. The valve will open with either RHR pump operating and system flow less than 2000 gpm. The valve will automatically close when RHR flow exceeds 2000 gpm.
Based on the above, the as-found position of V10-16B on April 25, 1985 would not have adversely affected the operability of the RHR system.
There were no further discrepancies noted with the minimum flow valve during the remainder of the inspection period. Safeguard system valve lineup control and operator shift turnover reviews will be reviewed further by the inspector during future routine inspections. The inspector had no further comment on this item at this tim.
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l 5.6 Radiation controls established by the licensee, including radiological surveys, condition of access control barriers, and postings within the radiation controlled area were observed for conformance with the requirements of 10 CFR 20
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and AP 0503. Radiation work permits (RWPs) were reviewed to verify with proce-
dure AP 0502. Work activities in progress were reviewed for conformance with
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RWP requirements. Confirmatory radiation surveys were performed by the inspector.
RWPs85-327, 376, 377 and 232 were reviewed. No inadequacies were identified.
- The following items warranted-additional review.
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5.6.1 Plant operators noted minor steam leaks in, the turbine high pressure heater bay area during routine operational rounds on April 25, 1985. Leakage was noted from the flange on the 'D' turbine control valve and from a manway
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on the steam piping to the 'B' moisture separator. The high pressure heater bay is normally a locked high radiation area, and is not routinely accessed by
plant workers. The inspector reviewed the results of air samples taken in the
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vicinity of the leaks and noted that air. activity remained at or below 1.0 X
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E-9 uCi/cc.
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Plant personnel reported that the control valve leakage had worsened slightly
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on May 2, 1985 and the flange condition would be evaluated further to determine i
whether a plant shutdown would be required to fix the leak, or if the leak could wait for repair at the scheduled refueling outage. The inspector. observed the control valve and noted the steam plume from the flange to be.about.'6' inches
long and 3 inches wide.
No visible' plume was evident from the manway on the moisture separator.
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The leakage posed no hazard to plant personnel. The inspector had no further comment on this item at the present time. The condition'of the steam leaks and
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licensee actions to repair them will be followed during subsequent routine i
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5.6.2 During operations on May 3, 1985~to prepare spent control rods for
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I shipment offsite, control rod #15 dropped from a handling tool to the bottom
i of the spent fuel pool. The control rod did not strike any spent fuel or
other critical components. No radiation releases occurred as a result of the incident. The rod was recovered from the pool and placed in the shipping cask
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for offsite disposal.
The inspector interviewed the Maintenance and Reactor Engineering personnel i
responsible for the fuel pool work to determine the cause of the incident and the actions taken to prevent recurrence. The control rod dropped during handling in the control rod inverter as a result of the mechanical failure of a shaft coupling bolt in the inverter latching mechanism. The latching mechanism
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was repaired under the direction of the Torrey Pines vendor representative. The
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inverter was subsequently used satisfactorily.
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Licensee personnel identified no damage to the pool floor as a result of the
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incident. The inspector examined the pool floor using binoculars from the 345 j
foot elevation on May 6,1985 and noted no indications of damage.
No inadequacies were identified.
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5.6.3 Activities in' progress-on May 6,1985 to prepare miscellaneous
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material for shipment offsite was _ reviewed to determine that approved pro-cedures governing the activity were available and in use by plant personnel.
Procedure precautions and prerequisites were verified to be observed and/or satisfied. The inspector observed activities for conformance with the re-quirements of RWP 85-461.
No discrepancies were noted. The following pro-cedures were reviewed:
+ -OP 2202, Cask Handling Procedure for FSV-1 Cask, Revision 1,"4/5/85;
+ OP 2203 Procedure for Processing Spent Control Rods Prior to Disposal, Revision 1, 1/21/85; and,
+ OP 2204, Preparing LPRMs and Fission Chambe'rs for Disposal, Original, 4/8/85.
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No inadequacies were identified.
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5.7-Implementation of jumper and lifted lead l request 85-19'(J/LL) was re~-
viewed to verify that controls established by AP!0020 were met; no conflicts -
with the Technical Specifications were created;. requests.were properly approved prior to installation; and, a safety evaluation was prepared in accordance with 10 CFR 50.59. The recuest was issued in conjunction with work. request l 85-173 to disconnect the feec for dilution pump P91-1B to provide actemporary supply to the new construction office building. The power supply will be taken from compartment 7C on Switchgear #11 which is'non-safety related.
The change affected the facility description as presented in FSAR Section 9.2.5 and Figure 11.6.1.
No unreviewed safety question was involved in the change since the dilution pump is only required for liquid discharges to the Connecticut River, which are not routinely made. A dilution pump can be restored to an operable status if a discharge is required.1The pump interlock that prevents a discharge unless a dilution pump breaker is closed was disconnected to prevent
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an inadvertent discharge without dilution. No unacceptable technical issues were identified.
The inspector noted that the licensee identified that a safety evaluation was not performed for a similar jumper and lifted lead request (84-53) for dilution pump P91-1A. The present SER was administrative 1y applied to the fomer request.
This apparent violation of the requirements of AP 0021 and Technical Specifica-tion 6.5 will be reviewed further on a subsequent inspection to review the actions taken to prevent recurrence (UNR 85-14-01).
5.8 Tagging and controls of equipment released from service were reviewed to verify equipment was controlled in accordance with AP 0140, VY Local Control Switching Rule. Controls implemented per Switching' Orders85-269, 85-252,85-248 and 85-253 were reviewed and no discrepancies were note.
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6.0 Operational Status Reviews The operational status of standby emergency _ systems and equipment aligned to support routine plant operation was confirmed by direct review of control room instrumentation. Control room panels and operating logs were reviewed for. in-dications'of operational problems. Licensed personnel were interviewed re-garding existing plant conditions, facility configuration and knowledge of recent changes to the plant and procedures, as applicable. Acknowledged alarms were reviewed with licensed personnel as to cause and corrective actions being taken, where applicable. Anomalous conditions were reviewed further.
Operational status reviews were performed to verify conformance with Technical Specification limiting conditions for operation and approved procedures. The following items were noted during inspector reviews of plant operational status.
6.1 During routine operations at full power on April-1, 1985, plant operators noted that the radiation monitor for main steam line 'C' was drifting low. The monitor and channel were placed in a tripped condition at 2:30 P.M. to generate a half scram and isolation signal pending calibration of the unit. Technicians replaced the control module and the channel was declared operable at 3:16 P.M.
following completion of calibration checks.
No inadequacies were identified.
6.2 While operating at full power'on April 2,1985, an inadvertent Reactor Building isolation occurred at 9:40 A.M. during the performance of routine testing per OP 4326.
Both trains of the Standby Gas Treatment system also started. Plant operators reset the isolation signal and restored nomal building ventilation. A report was made to the NRC Duty Officer at 10:10 A.M. in accordance with 10 CFR 50.72(b)(2)(ii).
The inspector reviewed OP 4326 and interviewed Instrument and Control personnel responsible for the test. The isolation occurred due to personnel error when the' refuel floor zone radiation monitor 17-453B was placed in the test position instead of the intended building ventilation monitor 17-4528. The control modules for both monitors are physically adjacent to each other. The person performing the test was a new technician who was undergoing on-the-job training with a senior technician at the time. The inspector reviewed OP 4326 and 'detemined that the test instructions were adequate.
No inadequacies were identified.
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6.3 During routine operations on April 2,1985 to transfer torus water. to the radwaste system per OP '2124, the control room operator inadvertently opened the drywell spray valve, V10-31A, instead of the intended torus cooling valve et 8:55 P.M.
The operator realized his mistake and imediately shut the spray valve. However, water leaked by the seat of the second (scries) drywell. spray valve, V10-26A, and some drywell spray did occur for an estaimated two minutes during the cycle time of the 31A valve. Plant operators reviewed'drywell para-meters and noted changes in the drywell bulk air temperature and the return air temperaturefordrywellrecirculationunit(RRU)#1. No affects were noted on drywell pressure, or on drywell to torus. differential pressure. Drywell bulk
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e air temperature changed from.127 degrees F to 107 degrees F and back to L
normal over about an hour period. RRU #1 temperature decreased from 112
degrees F to 101 degrees F over the same period. No other anomalies were l
noted_ in drywell conditions or in the performance of plant equipment; The inspector discussed the licensee's assessment' of the event with the.
Operations Superintendent on April 3,1985. l The incident resulted in a 0.1
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gpm increase in the leakage collected by the drywell floor drain sump. The licensee considered that the amount of water passed through the drywell spray
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header to be small and not significant enough to warrant imediate investiga-
-tion within the drywell. An examination for evidence of damage from the spray will be conducted during the next drywell inspection, scheduled in September,
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1985 when the plant shuts down for the refueling outage.
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No inadequacies were identified. This item is considered open pending NRC
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review of the drywell inspection results (UNR 85-14-02).
6.4 Plant operators bypassed two LPRMs during the inspection period due
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to indications that the detectors were either failed or drifting.LPRM 08-09B
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was bypassed at 5:50 P.M. on April 19, 1985. This was the second input removed from APRM 'E' (LPRM 24-17D was previously bypassed), which left 18 operable in-
puts to the APRM channel.LPRM 16-19A was bypassed at 3:05 A.M. on April 23 -
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1985, which is assigned to APRM 'D' and shared with APRM 'A'.
There were 19 operable inputs to APRMs 'A' and 'D' after bypassing LPRM 16-09A.
Plant personnel performed checks in accordance with OP 2425 following each LPRM failure to verify that the stored A(m) constants were still representative of
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the flux in the affected locations for use in P-1 calculations. No inadequacies
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were identified.
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6.5 A 100 volt ground occurred on the negative side of the 'B' 125 VDC sta-l tion battery at 8:25 P.M. on April 22, 1985. The battery remained fully operable.
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Maintenance personnel were notified to investigate the cause of the ground. The
ground cleared at 11:30 P.M. without further action by licensee personnel ~. A
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i 125 volt ground recurred at 5:35 A.M. on April 25, 1985 and was identified to be
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associated with circuit 8 on distribution panel DC-2 during subsequent investiga-l tions. Circuit 8 feeds the panel alarms in the radwaste control room. Plant i
technicians identified and repaired a control relay in the radwaste panel alarm
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circuit and the 'B' station battery ground was cleared at 9:30 A.M. on April 22, 1985. No inadequacies were identified.
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7.0 Licensee Event Report (LER) Followup i
l LER 85-05 dated April 19, 1985 was reviewed in the NRC Resident and Regional
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Offices to verify that:
the report clearly described the event and identified
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its safety significance; the event cause was identified and corrective actions i
taken (or planned) were appropriate; and, the report satisfied the requirements
of 10 CFR 50.73.
No inadequacies were identified.
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8.0 Surveillance Activities 8.1 The inspector reviewed portions of the surveillance tests listed below to verify that testing was performed in accordance with administrative require-
,ments. The review included consideration of the following:
procedures
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technically adequate; testing performed by qualified personnel; test data demonstrated confomance with Technical Specification requirements; test data anomalies appropriately resolved; surveillance schedules met; test results re-viewed and approved by supervisory personnel; and, proper restoration of systems to service.
+ OP 4326. Reactor Building Ventilation and Refueling Floor Radiation Monitor, Revision 7, 4/2/85
+ OP 4308, APRM Calibration, Revision 5,4/12/85
+ OP 4120, HPCI Monthly Functional, 4/22/85
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+ OP 4121 RCIC Monthly Functional,~4/30/85
+ OP 4126, Diesel Generator Operational Readiness, 4/8,4/19,4/23/85
+ OP 4124 RHR Valve Operability, 4/2,4/10,4/23/85'+ -
+ OP4115,PrimaryContainmentSurveillance,(reviewed):4/22/85
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+ OP 4334, Automatic Initiation Test 'of PCIS. Valves,!(reviewed) 4/22/85
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No inadequacies were identified. The items.below warranted inspector followup.
8.1.1 High vibration readings were recorded on the HPCI and'RCIC pumps during routine testing and further evaluation for. system operability was required in accordance with Article IWP-3200 of ASME Code Section XI.
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Testing of the HPCI system on April 18,.1985 showed vibration levels significantly higher than the February and March readings 'at locations X1, X2, X3 and X4, which were measured at 4.5. 4.0 and 2.5 and 3.2 mils, respectively. These readings were in excess of the Required Action limits set at 3,1.5,1.5 and 1.5 mils, respectively.
Evaluation of the 4/18 results was completed within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />, which included a second measurement of the pump vibration readings on April 22, 1985. The second measurement showed all bearing readings except X2 to be within the acceptable range and consistent with the fomer results. The vibration reading at location X2 was in the Alert Range at 1.5 mils and system retest within 2 weeks was scheduled.
Pump vibration was measured in the acceptable range during subsequent testing.
The vibration readings on both dates were taken with the IRD Model 306 vibration instrument. Subsequent investigation by the licensee identified frayed wires internal to the vibration instrument which affected and probably caused the anomalous readings on April 18, 1985.
Testing of the RCIC system at 3:20 A.M. on April 29, 1985 showed a vibration reading at location X2 at 2.0 mils, which was greater than the Action limit of 1.5 mils. The system was run again at 7:00 P.M. on April 29, 1985 to verify the earlier readings. The second set of readings showed all vibration readings within the acceptable range. Vibration readings remained within the acceptable range during subsequent testin.. #
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The inspector had no further consnent on the HPCI and RCIC system operability based on the Inservice Test program data. However, the inspector noted that the licensee uses the full 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> period to evaluate vibration readings, even-when the vibration values are known to exceed the ' Required Action' level, which would require that the pump be shutdown and declared inoperable. A retest of the component to verify the initial set of readings is included in the evaluation period. The requirements of the 1974 and 1980 versions of IWB-3230 are somewhat vague on the matter of ' Corrective Action' and subject to varying interpretation.
This item is considered open pending further NRC review to determine whethe the c
licensee's implementation of the IST program is in accordance with the require-ments of Section-XI (UNR 85-14-03).
8.1.2 The inspector reviewed the testing completed per OP 4334 $n August 1, 1984, May 26, 1983 and November 25, 1981 to demonstrate operability of the logic channels for the primary containment isolation valves. The inspector noted that the test was completed satisfactorily on August 1,1984, after licensee personnel discovered and corrected a mistake in procedure steps 22 and 26 concerning PCIS valves V38A and 388, the series suction valves for the primary containment air compressor. The test was apparently not completed satisfactorily during 1983 and 1981.
Procedure step 22 directs test personnel to verify that valves V72-38A/B are closed. Logic relays 16A-K23 and K24 are then manually de-energeized to simulate activation of a drywell isolation signal.
Procedure step 26 directs test personnel to verify that valves 38A/B go closed. This inconsistency was de-tected in 1984 and a procedure change was made to test proper operation of the logic. This inconsistency was apparently not detected during the 1981 and 1983 tests, based on annotations on the data sheets which indicated that the valves were checked closed in step 22, and verified to go closed in step 26. Satisfac-tory completion of the 1984 test verified proper operation of the PCIS logic.
The apparent failure to detect the procedure inadequacies in 1983 and 1981 con-stituted a failure to conduct a complete test of the primary containment isola-tion logic in accordance with Technical Specification 4.7.
The inspector's findings were discussed with the Instrument and Control Engineer-ing Assistant on April 23, 1985. The licensee was aware of the problems experienced during the 1984 test and a note had been appended to the OP 4334 procedure file to correct the instructions during the next procedure update.
The inspector's findings regarding the 1981 and 1983 tests, which were based on
records in the Document Control microfiche file, required further review to
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determine whether the procedure discrepancies had been identified.
l The licensee stated that problems had been previously noted with logic tests
similar to OP 4334 which direct test personnel to verify either proper position-ing or proper operation of multiple components in a single procedure step, with-o
out providing an individual verification / sign-off block for each component. A l
program is in progress to revise the logic tests to provide such verification l
blocks as procedures become due for biennial review.
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This item is considered open pending furtter hRC review of the 1981 and 1983 test records for OP 4334; further review cf the scope and schedule for com-plating the logic procedure upgrades; and, pending further review of logic test results to determine whether the findings related to OP 4334 are an isolated caseor;indicativeofagenericproblem(UNR 85-14-04).
8.2 The inspector reviewed on April 26, 1985, the scope of additional surveillance testing the licensee scheduled for performance during the period of April 28 - May 2, 1985. The testing was done using the normal technical specification tests and no credit was given for the completion of the normal surveillance program. The tests selected for performance are identified in Attachment 1 to this report.
No discrepancies were identified. The surveillance test results will be reviewed during a subsequent routine inspection.
9.0 Maintenance Activities
.s The maintenance request log was reviewed to detemine the scope and nature of work done on safety related equipment. :The following items were considered.
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during review of maintenance work:
the repair of safety related equipment received priorit Technical Specification limiting conditions for operation (LCOs)yattention;were met while components were out of service; replac parts were obtained from approved stock; alternate surveillance testing was performed as required; system tagging was proper; systems were properly returned to service; and, perfomance of redundant safety related systems was not. impaired.
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+ MR 85-568, Fuel Oil Storage Tank Drain'Line
+ MR 85-642 Drywell Hydrogen-Oxygen Analyzer System A
+ MR 85-648, Drywell Hydrogen-Oxygen Analyzer System B
+ MR 85-650, B Diesel Generator Fuel Oil Check Valve
+ MR 85-707 B 125 VDC Station Battery Ground
+ MR 85-435, A Diesel Generator Cylinder #9 Injector Leak The following item warranted inspector followup.
9.1 Diesel Generator Fuel Oil Header Check Valves The B Diesel Generator was removed from service for corrective maintenance on April 19, 1985 to repair a faulty fuel oil header check valve located on the engine skid. The fuel oil check valve was leaking and, if the condition were left uncorrected, could cause a longer starting time for the engine. The Teledyne check valve recomended by the diesel manufacturer has a seat material made from BUNA-N, which has been found by the licensee to swell in a fuel oil environment.
Fuel oil check valves were last replaced on the B diesel on August 27,1983(MR83-1597), andontheAdieselonOctober5,1982(MR82-1197).
A new check valve was installed that uses a Viton seat material, which was found by the licensee not to swell when exposed to fuel oil. The B diesel was returned to service on April 19, 1985 following operability testing. The check valve on the A diesel was: subsequently changed out on April 23, 198 y
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The inspector had no further comment on diesel generator operability. How-ever, this item is considered open pending further NRC review to determine:
(1) what actions have been taken by the licensee to review this matter for reportability to the NRC under 10 CFR 50.73 and 10 CFR 21; and, (ii what actions have been taken by the diesel manufacturer (Fairbank Morse))to correct the condition and/or notify other users of the problem (UNR 85-14-05).
9.2 Diesel Generator Alternate Surveillance Testing Both diesel generators were removed from service for corrective maintenance during the inspection period. As noted above, the B diesel was removed from service at 8:10 A.M. on April 19, 1985, to replace a fuel oil check valve. The valve was replaced by 8:20 A.M. and a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> operability run was started at 8:40 A.M.
The diesel was declared operable at 9:45 A.M. on April 19, 1985. The following surveillance testing was completed during the mid shift on April 19, 1985, prior to removing the B diesel from service: RHR system samples prior to starting the RHR and RHRSW systems; HPCI system; RCIC system; and, drywell to torus vacuum breakers. The last monthly surveillance run on the A diesel was on April 8,1985 and there was no test run on the A diesel on April 19, 1985.
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-The A diesel was subsequently removed from service at 9:15 A.M. on April 23, 1985 to replace the fuel oil check valve, repair a flange leak on the iniector for the #9 cylinder, and repair miscellaneous oil leaks. An operability test of the diesel was started at 5:08 P.M. following repairs and the diesel was declared operable at 7:00 P.M. on April 23, 1985. The following alternate
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system testing per Technical Specification 4.5 was completed while the diesel was out of service:
core spray system valves; RHR system chnistry samples; and, RHR system valves. There was no testing completed on the RHR or CS pumps, or on the B diesel generator.
This matter was discussed with the Operations Supervisor on April 24, 1985, and
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in a meeting with the Operations Supervisor and the Operations Superintendent on April 29, 1985. The licensee stated that alternate testing on the ' operable'
diesel was intentinally deferred toward the end of the repair period to avoid excessive testing of the diesel, if possible. The average time for completing the Technical Specification 3.5 alternate testing is 10 to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The licensee stated that, for the work done on April 23, 1985, the ESF pumps and the B diesel would have been tested by 8:00 P.M. if the' A diesel had not been returned to service. Additionally, the licensee stated that the presence and inclusion of 3 new auxiliary operators in the alternate testing on April 23, 1985 lengthened the time normally taken to complete the tests.-
The inspector noted thatareasonable time period for. completing all RHR'and CS system valve testing per OP 2124 and 2123 would be about 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, inclusive of distractions to the operator caused by routine shift business.
It appeared to the inspector that more testing could have. been done in the time allowed on the day shift on April 23, 1985. The inspector further noted that when one of two diesels is inoperable, the operability demonstration for the alternate diesel is the single most important verification'of all other components tested under technical specification 3.5.
While the inspector agrees with the licensee's
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general concern that the excessive testing of ESF equipment, especially the diesels, may over the long term adversely affect equipment operability and reliability, it appears that the licensee's approach to alternate system testing for the diesels may not meet the requirements of Technical Specifica-tion 4.5.H. which states...
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"During reactor operation, when it is determined that one of.the standby diesel generators is inoperable, all low pressure core cooling and containment cooling subsystems shall be demonstrated to be ope'able imediately and daily thereafter.
In addition, the operable diesel generator shall be demonstrated to be operable imediately and daily thereafter."
Technical Specification definition 1.0.D defines imediate to mean..."the required action will be initiated as soon as practicable considering safe operation of the unit and the importance of the required action." The inspector noted that alternate testing of a diesel per 4126 can be initiated within about one hour of the discovery of the need to do testing, with due regard for safe operation of the unit.
The inspector requested that the licensee review his policy for completing alternate surveillance testing for the diesels for compliance with the technical specifications. This item is considered open pendin review of the licensee's actions as noted above (UNR 85-14-06)g further NRC
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10.0 Staffing Changes The licensee infomed the inspector of several changes in the Maintenance Department staff during the inspection period. The Maintenance Supervisor was appointed to the position of Construction Superintendent for the recirculation pipe replacement project. The Maintenance Superintendent resigned from the company for employment elsewhere. Temporary reporting lines were established until these vacancies could be filled. No inadequacies were identified.
11.0 IE Bulletin 84-01 Review - TI 2500/12 The inspector reviewed licensee actions taken in response to IE Bulletin 84-01, Cracks in Boiling Water Reactor Mark I Containment Vent Headers, and General Electric Company)SIL #402, same subject.
Licensee actions were reviewed to verify that:
(1 the bulletin was received onsite, reviewed for applicability to the facility; and, (ii) corrective actions taken, or planned, were appro-priate. Licensee actions on the item were described to the NRC in letter FVY 84-110 dated September 14, 1984. The following is a sumary of the licensee's evaluations and actions. Additional reviews on this subject were documented in an internal memorandum dated March 7, 1984. Operation with the drywell inerted with nitrogen began on April 5, 1982.
The licensee's response and actions to this item was acceptable. No inadequacies were identifie _ _ - - - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _
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11.1 Inerting System Design Evaluation Large ambient evaporizers are installed at the site which use long feed lines as a passive protection feature to assure complete vaporization of the liquid nitrogen. The potential for introduction of nitrogen at less than 40 degrees F is remote and would require multiple system failures, including the failure of both primary and secondary temperature cutoff valves located outdoors between the ambient vaporizers and the purge gas heater.
Further, the VY design uses a 20 inch nitrogen supply line that enters the torus at a 90 degree angle from horizontal, but at a location 9 feet 6 inches off of torus centerline (the radius is 13 feet 8 inches). Thus the ring headers and i
downcomers do not line up with the nitrogen injection port and therefore are I
not subject to direct impingement of low temperature nitrogen. The only torus
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internal component directly below the nitrogen injection port is the suction strainer for the B core spray system, which is nomally submerged under several feet of water.
Based on the above, the licensee concluded that the inerting system design is adequate to prevent the injection of cold nitrogen into the containment.
11.2 Inerting System Operation l
The licensee reviewed inerting system maintenance records and detemined that no significant maintenance has been required since system startup. The licensee further concluded that system calibration, maintenance and operating procedures
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are adequate and that cold nitrogen injection would be detected and prevented l
using the existing procedures.
The details of the inerting system operating procedures and the licensee's
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detected will be followed on a subsequent insp(UNR ection. This item is considered open pending further review by the NRC staff 85-14-07).
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11.3 Test for Bypass Leakage After further consultation with GE regarding the proposed leakage test, the licensee concluded that an alternate approach would be suitable. The licensee reviewed the amount of nitrogen required to be added to the drywell to maintain differential pressure during normal operation. Any change in the make-up rate would indicate increased drywell to torus leakage and possibly a crack. The licensee reviewed nitrogen consumption records along with data from control room recorder 1-156-3 (drywell-torus delta-P) for the period from April 1982 to March 1984.
No unexplained transients were found and no indications of an increased make-up rate or leakage were noted.
The licensee's response indicated that the leakage test proposed by the SIL could not be performed at 0.75 psi since the VY technical specifications re-quire the drywell to torus differential pressure be maintained greater than 1.7 psi. The inspector noted that a leakage test conducted at 1.7 psi would have constituted a valid measurement and would have met the intent of the SIL recommendatio *
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11.4 Inspect Nitrogen Injection Line l
The licensee reviewed the requirements of this item and concluded that no UT l-measurements would be necessary. Any liquid nitrogen entrained in the flow f
stream would impinge on the first elbow encountered in the 200 feet of piping before the torus penetration. The licensee completed visual and internal boroscopic examinations of an elbow (at valve AC-9) in the carbon steel purge supply piping. The examination results were documented in Inservice Inspection Report YA-VT-1 dated July 12, 1984. The following additional areas were examined:
(1) ventilation supply "T" to the torus penetration and torus shell within 6 inches of the penetration; and, (ii) locations inside the torus at the injection line penetration and the inner shell. No evidence of liquid nitrogen carryover was found.
The inspector completed a visual inspection of the purge supply piping at valve AC-9 and noted no anomalies, cracks or indications of cold nitrogen impingement.
11.5 Containment Inspection The licensee did not inspect the downcomers and the ring headers since the loca-tion of the injection line with respect to these items would preclude impinge-ment, as described in section 11.1 above. An inspection of the area surrounding the penetration and any internal components that could be impinged by nitrogen were inspected during the 1984 refueling outage. The results were documented in ISI report YA-VT-1 dated July 12, 1984. No indications of nitrogen impinge-ment were found.
The inspector toured the torus area around the nitrogen purge injection penetra-tion and noted that the configuration of the penetration was as described in the licensee's response.
12.0 Annual Emergency Preparedness Exercise The inspector participated in the NRC review and evaluation of the 1985 emergency preparedness drill conducted on April 17, 1985. The scope of the NRC review and the findings from that inspection are documented in NRC Region I Inspection Report 50-271/85-13.
13.0 Management Meetings Preliminary inspection findings were discussed with licensee management periodi-cally 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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ATTACHMENT 1.
The additional-surveillance tests from the technical specification surveillance
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' test program scheduled for perfonnance during the period fran April 28.- May. 2, 1985 were as listed below.
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OP 4111, Control Rod Exercise-OP 4123, Core Spray System
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OP 4113.)tSIV Closure OP 4121 Service Water: System
OP 4120. HPCI Functional OP,4350 Containment High Range ~ Monitors OP 4121, RCIC Functional OP'4382, Stack High Range Monitors ~
OP 4115 Vacuum Breaker Testing OP 4351, RHR Shutdown Permissive.
OP 4113 MSIV Partial Closure OP 4358. HPCI; Steam Space Temperature OP 4126, Diesel Generators OP 4319 RPS 1st Stage Turbine Pressure OP 4116, Secondary Containment OP 4210,- Quarterly Battery Surveillance.
OP 4172 Reactor Vessel Level OP 4020, Cable Penetration Seals.
OP~ 4124. RHR Pump and Valve OP-5203, Shock Suppressors
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OP 4124. RHRSW Pump and Valve
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