IR 05000245/1989027
| ML20012B377 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 02/26/1990 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20012B376 | List: |
| References | |
| 50-245-89-27, NUDOCS 9003140293 | |
| Download: ML20012B377 (23) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION I-Report No.:
50-245/89-27 Docket No.:
50-245 I
License No.
DPR-21 I
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. Licensee:
Northeast Nuclear Energy Company
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P.O. Box 270
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F Hartford, CT 06101-0270 j
Facility Name: Millstone Nuclear Power Station, Unit I l
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. Inspection at: Waterford, Connecticut Dates:
December 5, 1989 - January 8, 1990 f
Reporting
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L Inspector:
D. A. Dempsey, Resident Inspector
l Inspectors:
W. J. Raymond, Senior Resident Inspector, Millstone Station
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D. A. Dempsey, Resident Inspector, Millstone Unit 1
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Approved by:
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DonaldR.Haverkamp,Chieff Date Reactor Projects Section 4A Division of Reactor Projects l
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Inspection Summary:
Inspection Report No. 50-245/89-27 Areas Inspected:
Routine resident inspection of plant operations, surveillance, maintenance, previously identified items, evaluation of licensee self-assessment, i
security and radiological controls.
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Results:
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General Conclusions on Adequacy, Strength or Weakness in Licensee brogram
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l Engineering department support of licensed operators regarding guidance j
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on low gas turbine generator oil and battery room temperatures, and
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matatenance of isolation condenser shell makeup supplies was considered a
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licensee strength.
(Sections 3.2.1,3.2.2,5.1.1)
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PDR ADOCK 05000245 i
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. A weakness was identified during the performance of containment isolation valve surveillance testing concerning operations department personnel awareness of recent changes to licensee inservice test program requirements.
(Section6.1)
The lack of a coordinated effort to resolve station battery room temperature problems indicates a need for greater sensitivity to the affect of non-safety-related support equipment on safety-related components.
(Section 3.2.1)
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Unresolved Items
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Six previously unresolved items were closed. (Section 5.3)
One unresolved item was opened regarding communication of inservice
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test program requirements to operations department personnel. (Section 6.1)
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TABLE OF CONTENTS Page 1.0 Persons Contacted........................................... I 2.0 Summa ry of Facili ty Acti vi ti e s.............................
3.0 Plant Operations (IP 71707)*...............................
3.1 Control Room Observations.............................
3.2 Plant Tours...........................................
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3.2.1 Low Main Station Battery Temperatures..........
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3.2.E Gas Turbine Generator Hydraulic Power Unit Low 011 Temperature............................
3.3 Review of Plant Incident Reports.....................
4.0 Radiological Controls (IP 71707)...........................
4.1 Posting and Control of Radiological Areas.............
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5.0 Maintenance / Surveillance (IP 62703/61726/92701)............
- 5.1 Observation of Maintenance Activities.................
5.1.1 Repair of Fire System Post Valve 1-Fire-40.....
5.2 Observation of Surveillance Activities................
5.2.1 1-SG-6 Failed Surveillance.....................
5.2.2 Inservice Testing / Reactor Cleanup System Isolation Valve T1 ming................................
5.3 Previously Identified Items...........................
5.3.1 (Closed) Unresolved Item 50-245/85-30-01, Limitorque Operator Wi ri ng............................ 10 5.3.2 (Closed) Unresolved Item 50-245/89-14-02, Hydraulic Snubber Fa11ures............................
5.3.3 (Closed) Unresolved Item 50-245/89-17-03, Hydraulic Control Unit Seism 1 city.....................
5.3.4 (Closed) Unresolved Item 50-245/89-12-03, Operating Shift Composition During Changing Plant Conditions............................................
5.3.5 (Closed) Unresolved Item 50-245/89-12-02, Followup of Recirculation Pump Seal Failure Event.....12 5.3.6 (Closed) Unresolved Item 50-245/89-04-01, Housekeeping and Piping and Instrumentation Diagram Discrepancies........................................
6.0 Security (IP 71707).......................................
6.1 Security Tours.......................................
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Page 7.0 Safety Assessment / Quality. Verification (IP 92700)..........
7.1 Licensee Event Report Review..........................
1 7.1.1 LER 86-006-03:
Failure of 1-MS-ID and 1-MS-20 to C1ose.......................................
l 7.1.2 LER 88-10-01: Hydraulic Snubber Failures......
7.1.3 LER 89-018-00: Missing Hydraulic Control Unit Straps.........................................
7.1.4 LER 89-019-00:
Failure to Complete Surveillance
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i n Re q ui red Ti me...............................
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7.1.5 LER 89-021-00: Reactor $ cram on Turbine Stop t
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Valve C1osure..................................
7.2 Periodic Reports......................................
8.0 Reactive Inspection Activities (IP 92701)..................
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8.1 ASCO Salenoid Va1ves..................................
9.0 Management Meetings (IP 30703).............................
- The NRC inspection manual inspection procedure (IP) or temporary instructions (TI) that was used as inspection guidance is listed for each
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applicabla report section.
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i DETAILS i
1.0 Persons Contac gd
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Interviews and discussions were conducted with licensee (Northeast Nuclear Energy Company) staff and management during the report period to obtain information pertinent to the areas inspected.
Inspection findings were discussed periodically with the supervisory and management personnel identified below.
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- S. Scace, Millstone Station Superintendent
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J. Stetz, Unit 1 Superintendent R. Palmieri, Unit 1 Operations Supervisor W. Vogel, Unit 1 Engineering Supervisor
P. Prezkop, Unit 1 Instrument and Controls Supervisor
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N. Bergh, Unit 1 Maintenance Supervisor
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- Attendee at post-inspection exit meeting on February 9,1990.
2.0 Summary of Facility Activities
Mi-11 stone Nuclear Power Station Unit 1 (Millstone 1 or the plant) was at i
full power (100 of rated thermal power) at the start of the inspection -
period. On December 17, while at 65% of rated power for routine main steam isolation valve testing, repeated rod drift alarms were received on control rod 10-35. After determining that the cause of the drift was seat
1eakage through the inlet scram valve, the control rod was fully inserted
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into control the core and its hydraulic control unit isolated. At 5:45
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a.m., on December 18, repairs were completed, and the control rod was
fully withdrawn for post-maintenance scram time testing. At 8:36 a.m.,
the control rod was successfully scrammed and by 9:12 a.m., power ascension commenced.
Full power operation was achieved at 11:35 a.m.
and maintained except for short power reductions to 80% on December 28 and January 4 to conduct turbine stop valve testing. While at 80% of
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rated power on January 4, reactor feed pumps were shifted to facilitate
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isolation of the
"A" condensate booster pump for mechanical seal repair.
By 9:30 a.m., January 4, full power was restored using the two remaining condensate booster pumps and continued for the remainder of the inspection
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period.
NRC Activities Routine NRC resident inspection involved 76.5 regular hours, 23 backshift hours, and 1.5 deep backshift hours.
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3.0 Plant Operations
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3.1 Control Room Observations Control room instruments were observed for correlation between channels, proper functioning, and conformance with technical r
specifications. Alarm conditions in effect and alarms received I
in the control room were discussed with operators. The inspector periodically reviewed the night order log, tagout log, plant
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incident report log, key log, and bypass jumper log.
Each of the j
respective logs was discussed with operations department staff. No
inadequacies were noted.
F 3.2 Plant Tours
The inspector observed plant operations during regular and backshift I
l tours of the following areas:
Control Room Switchgear and Battery Rooms Diesel Generator Room
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Turbine Building Intake Structure
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Reactor Building Gas Turbine Generator Building l
During plant tours, logs and records were reviewed to ensure compliance with station procedures, to determine if entries were correctly made, and to verify correct communication and equipment status. The following items were identified:
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3.2.1 Low Main Station Battery Temperature During routine review of Millstone 1 operating logs, the inspector noticed that 'B' station battery room temperature had been less than 60 degrees F on December 23, 1989. Optimum performance of this safety
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related battery occurs at 77 degrees F; as battery temperature decreases, so does its capacity.
The concern, therefore, is the ability.of the battery _ to perform its intended safety function in a
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degraded environment.
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Each main station battery at Millstone I consists of 60 series-connected Gould, Incorporated type NCX lead calcium cells.
-They are designed to supply their connected emergency loads for eight hours without re-charging and have a capacity of 2550 ampere-hours.
Gould technical manual 1-G-16-3, Station Battery Installation and Operating Instructions, specifies an operating electrolyte temperature range of 60 - 90 degrees F.
Millstone 1 updated final safety analysis report (VFSAR) section 8.3.2.1.1.1, Class IE 125vde Power Systems, specifies an annual average battery room temperature of approximately 77 degrees'F.
Operating procedure OP 344A, 125 Volt DC Electrical System, Revision 20, dated August 9,1989, precaution 4.4 specifies l
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that cell electrolyte temperature be maintained at approximately 77 degrees F.
Finally, Institute of Electrical and Electronics Engineers (IEEE) Standard 484-1975, Recommended Practice for Installation Design and Installation of Large lead Storage Batteries, endorsed by NRC Regulatory Guide 1.128, states, in part, that the battery area shall be ventilated to maintain design temperature.
NRC Region I inspection report no. 50-245/88-25 detailed the results of a safety-related battery systems audit performed in December 1988 pursuant to Region I Temporary Instruction No. 87-07.
Unresolved item no. 50-245/88-25-02 identified a lack of assurance in.the licensee program that actual battery temperatures be maintained I
within the prescribed range.
Inspector review of licensee surveill-ance records revealed 'B' battery pilot cell temperatures in 1987 anc 1988 as low as 54 degrees F and 44 degrees F, respectively, with yearly room average temperatures of 74 degrees F and 65 degrees F, respectively.
In response to the audit findings, the licensee placed calibrated thermometers in each battery room and added eight-hour checks of room temperature to 1-0PS-10.9, Plant Equipment Check Log, with a specified range of 60 - 90 degrees F.
On December 12, 1989, lifted lead and jumper request 1-89-55 documented the removal of electrothermal fire links (ETLs) from and shutting of battery
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room ventilation supply dampers 1-F05-12 and 1-FDS-14. The purpose was to isolate the rooms from cold outside air directed to the switchgear area by supply fans HVS-6A and -6B, and to permit battery exhaust fan HVE-6 to pull warm air from the battery charger area into the rooms. The inspector determined that the steam heating coils associated with HVS-6A and -6B were isolated and drained due to a long-standing design deficiency.
On December 23, to correct the low temperature condition, the licensee opened doors connecting the main turbine deck to the heating and ventilation fan rooms, and blocked open the HVS-6 supply fan discharge plenum door to draw warm air into the switchgear area.
A 480VAC fan was positioned to direct the warm air into the battery rooms, and dampers 1-FDS-12 and 1-FDS-14 were reopened and their ETLs reinstalled.
These expedients restored the temperature in 'B' battery room to the prescribed range.
The licensee sized the main batteries in accordance with IEEE Standard 485-1978, Recommended Practice for Sizing Large Lead Storage Batteries, and included an 11% margin for an electrolyte temperature of 60 degrees F.
Based on this calculation, the licensee engineer responsible for this system determined that the existing low temperatures would not affect battery capacity enough to render the battery inoperable. The inspector confirmed this result by performing a parallel calculation, validating the assumptions used, and derating the licensee results for 50 degrees F.
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i The licensee has been aware of the low room temperature p.roblem m
since at least 1987.
Likewise, the unreliability of the HVS-6
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heating coils is well known and documented.
Hence, the need to employ. trial and error methods to restore room temperature during
cold weather periods indicates a lack of sensitivity by the licensee to the effects of non-safety related equipment failures on the operability of safety-related equipment. Also, the
inspector noted that no coordinated approach to a. solution to the problem existed until the inspector identified his concerns to
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unit management. While technically sound, the derating of the l
battery for low temperature represents a reduction in its margin of performance and is no substitute for a definitive solution to
the problem.
Finally, during the course of his review, the inspector noted two inadequacies in the UFSAR. First, specification of an annual average battery room temperature fails to establish meaningful criteria for acceptable operation in that unacceptable extremes in temperature could result in an acceptable average. Second, the loads identified in the UFSAR as the basis for the eight-hour discharge cycle are out of date.
The licensee acknowledged the inspector's concerns and agreed that more aggressive followup was warranted. The licensee noted that the battery discharge cycle load discrepancy in the UFSAR
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had been identified as an inspection observation during its safety system functional inspection in 1988. A revision to the UFSAR is planned but deferred, pending incorporation of station blackout requirements.
The inspector had no further questions.
Unresolved-item no. 50-245/88-25-02 will remain open pending inspector review of licensee initiatives to assure satisfactory battery room temperatures.
3.2.2 Gas Turbine Generator Hydraulic Power Unit Low 011 Temperature On December 25, 1989, the licensee discovered that the gas turbine (G/T) generator hydraulic power unit (HPU) oil and engine compartment temperatures were less than that specified by procedure.
OPS Form 339-3, Gas Turbine Standby Check List, Revision 8 (performed every shif t) and OPS Form 339-2, Gas Turbine Generator Prestart Check List, Revision ll, Change 1 (performed prior to planned operation), specify an oil temperature range of 95 - 125 degrees F and engine compartment temperature range of 50 - 60 degrees F.
Actual oil and compartment temperatures were 90 degrees F and 46 degrees F, respectively.
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incident report 1-89-95 was initiated by the licensee as a result of
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this discovery.
The gas turbine generator is one of two on-site emergency power supplies, and starts automatically under selected accident conditions to provide emergency power to its associated emergency
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5-buses. The HPV provides the motive force to operate a servo-limiter which positions the turbine fuel valve.
Low oil temperatures can result in sluggish and unresponsive governor operation.
HPV oil temperature is monitored by a thermometer mounted on the outside of-the tank. Actual oil temperature may be up to 10 degrees F higher than indicated.
Licensee investigation determined that the HPU tank heater element is inadequate to maintain the required temperature band absent the p
aid of the engine compartment space heaters. One compartment heater
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was repaired expeditiously and raised the ambient temperature sufficient to restore the oil temperature in the HPU.
Repairs to the remaining compartment heaters are deferred, pending receipt of new heater elements. The licensee engineer responsible for the G/T determined initially that no operability concern existed for HPU temperatures as low as 80 degrees F.
On December 27, surveillance procedure SP668.2, Gas Turbine Fast Start Test, was performed satisfactorily, confirming this analysis.
The inspector plotted the kinematic viscosity of the oil used in the HPU (Mobile DTE-26) on an ASTM standard viscosity-temperature chart and estimated the viscosity for a temperature band of 80 -
125 degrees F to be 300 to 45 centistokes (est). An oil chart in the Woodward governor technical manual specifies a gross acceptable band of 650 - 7.5 cst comprised of an ideal range (65-20 cst),
limited operation at low temperature range (650-65 cst), and limited operation at high temperature range (20-7.5 cst).
Superimposing the characteristics of DTE-26 on the vendor oil chart indicated that operation in the temperature band specified by licensee procedure occurs largely on the low temperature limited operation region. At the inspector's request, the licensee engineer contacted the vendor
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regarding the meaning of the term " limited operation" and learned that the band applief to G/T operation in aircraft where HPV temperature is expected to decrese Erkedly as the aircraft gains altitude. Therefore, the operability of the G/T governor is not jeopardized by the low HPU oil temperatures experienced due to space
heater failures. As a long-term solution, the licensee is considering either increasing the capacity of the tank heater element or
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insulating the tank. The inspector will followup this issue as part of the routine inspection program concerning Class IE power systems.
3.3 Review of plant Incident Reports
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The Millstone 1 plant incident reports (PIRs) listed below were reviewed during the inspection period to (1) determine the significance of the events; (ii) review licensee evaluation of the events; (iii) verify the licensee's response and corrective actions were proper; and, (iv) verify that the licensee reproted the events in accordance with applicable requirements.
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following PIRs warranted inspector followup and are discussed in the inspection report sections cited below:
PIR 1-89-94, RWC System Valves Timing (Section 6.1)
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PIR 1-89-95, Gas Turbine Hydraulic Power Unit-Low 011
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Temperature (Section 3.2.2)
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PIR 1-90-01, Fire System Leak; 1-Fire-40 (Section 5.1.1)
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4.0 Radiological Controls 4.1 Posting and Control of Radiological Areas
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During plant tours, posting of contaminated, high airborne radiation, and high radiation areas were reviewed with respect to boundary identification, locking requirements, and appropriate hold points. No inadequacies were noted.
5.0 Maintenance / Surveillance 5.1 Observation of Maintenance Activities The inspector observed and reviewed selected portions of preventive and corrective maintenance to verify compliance with regulations, use of administrative and maintenance procedures, compliance with codes and standards, proper QA/QC involvement, use of bypass jumpers and safety tags, personnel protection, and equipment alignment and retest. The following activities were included:
AWO M1-89-12979, Inspect / Repair "C" Reactor Feed Pump Bearings
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AWO M1-89-13419 Inspect / Repair M10-35, Hydraulic Control
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Unit Inlet Scram Valve
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AWO M1-89-13420, Inspect / Repair M10-35, Hydraulic Control
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Unit Outlet Scram Valve AWO M1-89-12807, Repair 1-SG-6 (Failed Surveillance)
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AWO M1-89-12419 Repair Seals on "A" Condensate Booster Pump
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AWO M1-90-00156, Replace 1-Fire-40 Post Valve
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AWO M1-89-13739, Repair Gas Turbine Compartment Heaters
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No inadequacies were identified.
I 5.1.1 ' Repair of Fire System Post Valve 1-Fire-40 During the period of December 23-25, 1989, the licensee noticed higher than normal levels in the
"A" reactor building drain sump.
Coincidentally, it was observed that the fire system jockey pump was cycling approximately every three minutes.
Further investigation revealed water issuing from the housing of valve 1-Fire-40, a fire system loop isolation post valve located outside of the southeast corner of and serving the reactor building.
The licensee suspected,
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and later confirmed, that leakage from the cracked valve housing was
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entering an adjacent underground pipe chase, being pumped to the
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waste surge tank moat and then pumped to the reactor building sump.
On January 3, 1990, while excavating the valve, leakage increased such that the valve had to be shut, isolating eight hose stations and l
two sprinkler systems in the reactor building, and the gas turbine l
generator building spray system. 'The licensee entered technical specification limiting condition for operation action statements 3.12.B.2, Spray and/or Sprinkler Systems, and 3.12.D.3, Fire Hose
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L Stations, stationed the required fire watches and initiated plant incident report 1-90-1, Fire System Leak.
Since the affected fire system header is the normal supply of i-makeup water to the isolation condenser shell, makeup to this high pressure emergency core cooling system was shifted to the condensate storage tank.
The inspector noted good engineering staff support in providing detailed guidance to operators for ensuring the reliability of this supply in the event of a loss of normal station power (LNP), station blackout (loss of all AC power) and LNP with gas turbine generator failure.
The inspector also verified that appropriate safety measures were employed
during excavation and replacement of the valve.
i On January 5, the faulty valve was removed and the reactor building side of the fire header blanked, permitting pressurization of the reactor building system, if required.
On January 9, valve 1-Fire-40 was replaced and tested successfully, and the fire and isolation condenser systems returned to normal.
The inspector had no further questions regarding this maintenance activity.
5.2 Observation of Surveillance Activities Through observation and data review of surveillance tests, the inspector assessed licensee performance in accordance with approved procedures and technical specification limiting conditions of operation, removal and restoration of equipment, and deficiency review and resolution.
The following tests were reviewed:
EP 1051, Control Rod Scram Test Time Test, Revision 5
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SP 646.10, SGTS Valve Operability Test, Revision 2
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SP 780.1, Station Battery Weekly Inspection, Revision 6
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SP 788.3, Fire Pump Diesel Engine Batterit.s - Weekly
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Surveillance, Revision 5 SP-408J, Condenser Low Vacuum Scram Functional
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Test / Calibration, Revision 7 SP 608.26, Reactor Feedwater Pump Rotation Check Valve
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Readiness Test, Revision 5 OPS 6808, Electric Fire Pump Monthly Run, Revision 9, Change 1
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SP 623.8, Containment Isciation Valve Operability
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i Demonstration, Revision 11 l
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5.2.1 1-SG-6 Failed Surveillance During performance of surveillance procedure SP 646.10, Standby Gas Treatment Valve Operability Test, Revision 2, on December 26, 1989, valve 1-SG-6 failed to close within the full stroke time specified by the procedure. This air-operated butterfly valve is the cross-connect isolation downstream of the two standby gas treatment (SGT) system filter trains, and is tested pursuant to the licensee inservice test program.
Repairs to the valve
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operator were unsuccessful and the valve remained inoperable
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during the inspection period.
The inspector reviewed the technical specifications relating to tFo SGT system and operating procedure OP 329, Standby Gas Treatment System, Revision 15, dated November 29, 1989 and could
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find no reference to this valve. As a result of discussions with licensed operators and review of system diagrams, the inspector concluded that 1-SG-6 served no required safety function.
Normal operation of one SGT train fan with the opposite filter train is precluded by an interlock between the fan and its associated inlet valve.
Consequently, the inspector concluded that no safety concern existed regarding the long-term inoperability of this valve.
5.2.2 Inservice Testing / Reactor Cleanup System Isolation Valve Timing On December 20, 1989, surveillance procedure SP-623.8, Containment Isolation Valve Operability Demonstrations, was performed with the following results for two reactor water cleanup (RWC) system valves:
1-C0-28; 18.1 seconds to close,
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1-C0-3; 12.6 seconds to close.
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The acceptance criteria for these valves specified in OPS Form 623.8-1 were 14 to 18 seconds (1-C0-28) and 8 to 12 seconds (1-C0-3). Technical specification (TS) table 3.7.1, Automatic Isolation Valves, specifies a maximum operating time of 18 seconds for these valves.
The licensee operators immediately retested valve 1-CV-28, which closed in 17.9 seconds, and repeatedly cycled valve 1-CV-3, which was timed at 12.2, 14.8, and 13.4 seconds.
Since these values were less than the limit of TS table 3.7.1, the valves were considered operable, and the operators proceeded to restore the RWC system to operation in accordance with operations procedure OP-303, Reactor Cleanup System.
Upon attempting to slowly repressurize the system, valve 1-CV-2A, a one-half inch inlet bypass valve, failed to open.
System restoration was achieved by
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slowly jogging open the eight-inch header isolation valve,1-CV-2.
Plant incident report no. 1-89-94 was initiated to report the surveillance results, and valve 1-CV-2A was caution-tagged shut.
Upon consulting the Millstone 1 inservice test (IST) coordinator regarding valve 1-CV-3, the operators determined that the
procedure acceptance criterion was in error.
The data form had not been updated to reflect the stroke time reference values of the new valve motor operator installed during the refueling outage in May, 1989.
Later that day, the plant operations review committee (PORC)
l convened to consider the test results for valve 1-00-3.
Based on previously performed surveillance test results on the new
motor-operator, a new acceptance range of 13 1 15% seconds was
determined and incorporated into the test form. On December 21, the PORC met again and concluded that containment isolation valve 1-CV-2A was capable of meeting its safety function as required by
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TS table 3.7.1; that is, to stay closed upon receipt of an
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isolation signal. To guarantee function, the valve was danger
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tagged and its associated solenoid valve tagged deenergized.
Change 2 to OP 303 was also approvrid to provide specific instructions
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for RWC system restoration with valve 1-CV-2A unavailable. The
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inspector had no questions regarding valve 1-CU-2A.
i Valves 1-CU-3 and 1-C0-28 ere normally open, eight-inch, motor-operated gate valves located outside the cuntainment.
Their safety function is to isolate the RWC system froin the reactor upon receipt of a Group V isolation signal (reactor vessel low-low level).
Isolation also may occur on initiation of the standby liquid control system, to prevent boron removal, and failure of the RWCU system pressure reducing valve, to prevent system overpressurization.
In the event of a line break, the operator must manually shut the valves from the main control board.
The licensee tests the valves quarterly pursuant to TS 4.7 D.1.c, Primary Containment Isolation Valves, and the second ten year IST program for pumps and valves. TS 3.7.D.2 permits reactor
operation with an inoperable containment isolation valve provided that at least one valve in each line having an inoperable valve is in an isolated condition. On April 3, 1989, the NRC staff issued generic letter (GL) 89-04, Guidance on Developing Acceptable Inservice Test Programs. The GL provides guidelines to supplement the requirements of sections IWV-3413(a) and-IWV-3417(b) of the ASME Boiler and Pressure Vessel Code,Section XI regarding the relationship between TS and safety analysis stroke time limits and those reference values derived from IST results. When TS or safety analysis limits are greater than IST values, valve operability shall be determined by the lesser IST
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values.
In October,1989, the licensee coir.mitted to implement
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this guidar,ce, and in December, SP 623.8 was modified accordingly.
7n addition, section 8 of the licensee IST program was changed to require that a valve be declared inoperable immediately if its stroke time falls outside of the reference value i 15%.
Based on these considerations, the inspector questioned why i
licensee operators had retested valves 1-CV-3 and 1-CU-28 and restored the RWCU system to operation rather than declare the i
valves inoperable. The inspector discussed these concerns with licensee management and the shift supervisor involved in the test, and determined that the operators were unaware of the new
requirements of GL 89-04. (The superseded sections of the IST program would have permitted the immediate retest of the valves.)
The inspector reviewed IST records for the valves and verified I
that for valve 1-CV-3, a 13-second reference time is appropriate.
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For valve 1-CU-28,17.9 seconds is within the specified range of 17 1 15% seconds, but slower than previous tests.
The licensee has agreed to grease or readjust, and retest this valve during the next scheduled reduction in reactor power. During the course of the review, the inspector noted that the post-maintenance
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retests of both valves had not been entered into the IST record of tests.
This was immediately corrected by the licensee, who reviewed the data for ether program valves and found no further anomalies.
The inspector also observed that the generic IST t
program procedure, SP 1061, Power Operated Valves and Check Valve Operability Program, Revision 4, had not incorporated the requirements of GL 89-04.
The licensee indicated that a new revision was being drafted.
Finally, the inspectar discussed the matter with the operations department supervisor, who agreed that the cause was inadequate communication of IST program and GL requirements between the engineering and operations departments. The inspector will continue to monitor licensee implementation of ney; IST program requirements and performance of inservice testing as part of the i
routine resident inspection program.
The communication of IST
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program requirements to licensed operators is an unresolved item pending inspector review of licensee corrective actions (UNR 50-245/89-27-01).
5.3 Previously Identified Items 5.3.1 (Closed) Unresolved Item 50-245/85-30-01 Limitorque Operator Wiring This item consists of licensee failure to demonstrate qualification of internal wiring on Limitorque valve operators.
Previous NRC
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inspection (50-245/87-17) closecut of this issue was based on licensee valve walkdowns to verify equipment qualification including terminal block concerns addressed in information notice 83-72, and NRC
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inspection of the walkdown data. This item is administrative 1y
closed.
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5.3.2 (Closed) Unresolved Item 50-245/89-14-02. Hydraulic Snubber Failures
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Licensee event report (LER) 88-10, revision 00, dated December 13,
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1988, inaccurately ascribed the failm e of a safety-related hydraulic snubber oil reservoir to personnel error during a rebuild. As
reported in LER 89-07, dated May 11, 1989, the actual root cause of the failure entailed changes made by the manufacturer to the reservoir i
end plates which were not reported to the licensee. The inspector
verified that the licensee has amended LER 88-10 to reflect this new i
information.
This item is closed.
5.3.3 (Closed) Unresolved Item 50-245/89-17-03, Hydraulic Control Unit seismicity This item involves the discoverj by an NRC inspector, and subsequently
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by licensee personnel, of missing mett.1 restraining straps on four control rod hydraulic control units (HCUs).
Since no site-specific seismic analysis was available for the HCUs, the licensee concluded that the absence of the straps placed the units in an unanalyzed condition.
Based on the facts that the generic HCU seismic qualification test accelerations were much greater than that assumed
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in site-specific accident analyses, and that the main supports for t
the HCU accumulators were unaffected, the licensee concluded that the units would have remained functional during a seismic event.
Pursuant to 10 CFR 50.73 (a)(2)(ii) and (a)(2)(v), the licensee has issued a licensee event report which 15 reviewed in detail i
8.2.2 of this inspection report. The inspector had no furtner
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questions regarding HCU operability.
This item is closed.
5.5.4 (Closef Unresolved Item 50-245/89-12-03, Operating Shift Composition During Changing Plant Conditions During a startup on June 2, 1989, an automatic reactor scram on low main condenser vacuum occurred due to inattention to detail by licensed operators. As a result of its review of the event, the licensee committed to revise the operations department instruction governing shift crew composition in the control room during changing plant conditions.
The inspector reviewed Unit 1 Operations Departmental Instruction No.1-0PS-2.01, Shift Assignments and Schedule, Revision 27,
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dated July 10, 1989, and verified that the commitment has been
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conditions, the shift supervisor is expected to monitor plant parameters closely and minimize time out of the control room.
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Strict compliance to this requirement is enjoined when other L
control room operators have been newly upgraded, as the shift personnel will have only limited experience operating as a team.
This item is closed.
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5.3.5 (Closed) Unresolved Item 50-245/89-12-02, Followup of Recirculation Pump Seal Failure Event
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On May 29 and 30, 1989, Millstone I was shut down due to failure of a reactor recirculation pump seal. This item identified three
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NRC concerns regarding that event.
NRC inspector review disclosed an ambiguity in the
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recirculation system operating procedure, OP 301, regarding the lack of quantitative criteria for isolation of a recirculation pump. The ambiguity derives from the likelihood of thermal binding of pump isolation valves if closed prior to plant cooldown.
The inspector reviewed OP 301, Recirculation System, Revision 28, Change 1, dated November 15, 1989, and verified that more specific guidance has been provided to the operator; i.e. the
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pump shall be isolated if total drywell leakage exceeds the technical specification limit and is attributable to seal leakage.
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The inspector was concerned that the sole method of drywell
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leakege detection may not be adequate.
Drywell leakage rate is calculated from equipment sump pump-down readings (gallons pumped and time between readings). The licensee concedes that the method is cumbersome, but regards it to be adequate to determine and trend small leak rates.
Rates in excess of normal reactor coolant system makeup capacity are detectable through drywell radiation monitors, and temperature and pressure detectors.
Consequently, the licensee has no plans to upgrade the present leakage detection method. The inspector had no further questions regarding this issue.
Although the licensee initially notified the NRC Operations
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Center as required by its emergency plan, the inspectors felt that more frequent event updates concerning major changes in drywell leak rates may have been warranted during the event.
Licensee sensitivity to the initial and update notifications of events to the NRC will continue to be evaluated by the inspector
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during routine inspection and event followup. This item is closed.
5.3.6 (Closed) Unresolved Item 50-245/89-04-01: _ Housekeeping and Piping and Instrumentation Diagram Discrepancies
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This item arose as a result of the inspector's observations that
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(1) licensee troubleshooting of a control room temperature
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maintenance problem was hampered by inaccurate piping and instrumentation diagrams (P& ids), and (2) housekeeping and material conditions in the fan room areas (turbine building, elevation 42'6") were inadequate.
i In 1988 an engineer from the Northeast Utilities corporate office was temporarily assigned to Millstone 1 to coordinate the upgrading
of control room critical operations P& ids. By December of that year the project was complete and all required drawing change requests submitted. The inspector determined that the P&ID upgrading process has been completed and that adequate administrative controls exist to assure the accuracy of critical operations drawings.
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The inspector toured the turbine building fan rooms on three occasions during the inspection _gpr.iod, noted improvements in
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area lighting, piping insulation condition, material storage, and cleenliness, and concluded that licensee efforts to imprcve the material condition of the spaces are adequate. This item is closed.
6.0 Security Selected aspects of site security were ver.ified to be proper during inspection tours, including site access controls, personnel searches, personnel monitoring, placement of physical barriers, compensatory measures, guard force staffing, and response to alarms and degraded conditions.
6.1 Security Tours On December 4, 1989, the inspector observed the conduct of a fire
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drill at Millstone Unit 2.
The scenario consisted of a simulated large oil fire in the turbine building near the steam generator feed pumps requiring assistance from a local fire department.
The inspector verified that security personnel responded to the
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drill promptly and that, in accordance to the physical security plan, no delays were encountered by the fire department in gaining access to the site or acquiring the necessary escorts.
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7.0 Safety Assessment /Ouality verification
7.1 Licensee Event Reports Review Licensee event reports (LERs) were reviewed to assess accuracy, compliance with 10 CFR 50.73 reporting requirements, and adequacy of licensee corrective actions, and to determine if generic implications existed or if further information was required.
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Three LERs were reviewed.
i 7.1.1 LER 86-006-03:
Failure of 1-MS-10 and 1-MS-20 to Close l
This is the third update to this licensee event report (LER).
In 1986, the licensee reported that the " valve open" limit switch on j
main steam isolation valve (MSIV) 1-MS-10 had failed to reset due to warping of the switch contact block slide plate. While the failed switch provides only valve positir. dr.dication, an adjacent switch provides input to the reactor protection system to scram the reactor when the MSIV is less than 90 percent fully open. Therefore, the licensee initiated a substantial safety hazard determination pursuant to procedure NEO 2.01, Implementation of 10 CFR 21 Reporting of Defects and
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Noncompliance.
Revision I to LER 86-006, dated February 3, 1987, reported the results of the SSH determination.
Since only two of 32 switches had failed in service, and one had failed soon after the suspect parts had been replaced, it was concluded that the failure was due to improper adjustment and was random in nature. However, the LER expressed the licensee suspicion that due to the switch's location near the MSIV body, high temperature could be the root cause of the failure. Therefore, the licensee placed " stick-on" temperature detectors on the limit switch bodies to record ambient temperatures during power operation when the valves were
not readily accessible.
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Revision 2 the LER, dated October 29, 1987, reported that switch temperatures varied from 170 to 330 degrees F and that most of the switch phenolic internals exhibited warping (cithough the electrical characteristics were satisfactory).
During the 1987 outage the licensee replaced all of the switches' internals.
i Revision 3 to LER 86-006, dated September 22, 1989, reported the installation of 1/8-inch fiberglass insulating tape between the limit switch bodies and the MSIV switch mounting plate to reduce thermal conduction, hence the potential for heat-enduced degradation of switch phenolic components.
The inspector reviewed plant design change evaluation (PDCE) 1-88-70, dated May
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1, 1989, and had no questions regarding the adequacy of the i
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The switches involved are Namco model EA-740, and are environmentally
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qualified to 340 degrees F.
The manufacturer recommends replacement of the contact block and carrier assemblies every 20 years for
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continuous exposure to temperatures greater than 122 degrees F.
Depending on the date of manufacture, checks of contact resistance i
and replacement of contact block assemblies if greater than one ohm
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are recommended at four year intervals for temperatures greater than
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104 degrees F (switches manufactured from January,1978 to November,
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1980), and three year intervals for temperatures greater than 140 t
degrees F (switches manufactured af ter November,1980). Millstone 1 replaces the limit switch internals every refueling outage, an
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interval shorter than that recommended by the manufacturer.
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In light of the operating experience at Millstone 1, the l
recommendations of the switch manufacturer appear to be unrealistic, i'
and the inspector considered the accelerated replacement schedule and PDCE implementation by the licensee to be prudent.
Finally, the inspector considered that issuance of a third revision to the old LER
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reflected this issue. The efficacy of the design change implemented
by the licensee will be inspected following routine switch internals replacement during the next scheduled outage.
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7.1.2 LER 88-10-01:
Hydraulic Snubber Failures
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On September 22, 1989, the licensee updated this licensee event
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report (LER) to reflect new information regarding the failure of several ITT Grinnell hydraulic snubber reservoirs since 1984.
Section V of the LER,. " Additional Information", describes the
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failure mechanism as an improper fit between the reservoir glass i
and the end plate "0" ring groove.
Although not specifically
stated, the LER suggests as a root cause that the manufacturer had
made dimensional changes to the end plates without notifying the i
licensee.
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The correct identification of root cause is essential to the development and implementation of corrective actions to prevent recurrence of an event.
In this case, the immediate cause of the snubber failures was addressed by the purchase and installation of new snubbers.
However, the LER fails to address the issue of inadequate vendor information under corrective action. Through discussions with the responsible licensee engineer and review of the
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ITT Grinnell snubber technical manual, the inspector was satisfied that the information available to the licensee was current.
Further licensee corrective action cited in the original and updated LERs included a change to the hydraulic snubber maintenance prucedure.
The inspector reviewed maintenance procedure MP 739.1, Hydraulic Snubber Functional Test and Repair, Revision 8, Change 1, dated March 1,1989 and found that the required change had not been implemented.
The cognizant licensee engineer stated that the change has been submitted and will be incorporated into the next procedure revision.
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7.1.3 LER 89-01P-00: Missing Hydraulic Control Unit Straps I
The technical issues presented in this LER are discussed in detail 5.3.3 of this inspection report. The event was reported
pursuant to 10 CFR 50.73.(a)(2)(ii) and (a)(2)(v).
Upon identifying the problem, the licensee replaced the missing straps and verified that existing maintenance procedures provided adequate guidance for installation and removal of the straps. No
cause could be determined for the missing straps, but by process of elimination, the inspector agreed with the licensee that it is
logical to assume that personnel error was ultimately the cause.
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In its analysis of the event, the licensee concluded that there was a reasonable probability that the hydraulic control units would have remained functional during a seismic event and that no safety consequences ensured since no seismic event took place while the straps were missing.
The inspector cunsidered the latter statement to be unresponsive to 10 CFR 50.73(b)(3), which requires an assessment of actual and potential safety consequences and implications. This could include the availability of other systems or components which can perform the same function or reference to plant safety analyses.
The inspector had no further comments concerning this LER.
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While discussing NRC expectations with the licensee engineering staff regarding LER safety assessments and the symbiotic relation i
between identification of root cause and developmert of corrective action, the inspector found that Supplement No. 2 to NUREG-1022, Licensee Event Report System, dated September, 1985, was not available to the persons responsible for drafting LERs.
The licensee stated that this guidance would be made available in
the future.
7.1.4 LER 89-019-00:
Failure to Complete Surveillance in Required Time This event involved failure of the licensee to perform surveillance procedure SP-412L, Isolation Condenser Isolation Instruments Functional and Calibration Test, within the time interval required by technical specifications.
The event was reported pursuant to 10 CFR 50.73(a)(2)(1)Ib), is discussed in NRC Region I inspection report no.
50-245/89-23, detail 8.4, and resulted in a notice of violation (VIO 50-245/89-23-03).
The licensee identified the missed surveillance and took corrective
action to preclude recurrence of a similar event.
Further NRC assessment of licensee corrective action is pending the receipt of its response to the notice of violation required by 10 CFR 2.201.
The inspector had no further questions.
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7.1.5 LER 89-021-00:
Reactor Scram on Tu bine Stop Valve Closure
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On October 19,.1989 a reactor scram occurred due to a turbine
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trip on high reactor water level.
The high level resulted from failure of a feedwater regulating valve. The event was reported (
to the NRC pursuant to 10 CFR 50.73(a)(2)(iv), and has been
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addressed in NRC Region I inspection report no. 50-245/89-25.
The LER adequately addressed the requirements of 10 CFR 50.73, and the inspector had no further questions, t
7.2 Periodic Reports
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Upon receipt, periodic reports submitted pursuant to technical i
specifications were reviewed.
This review verified that the reported information was valid and included the required NRC data..The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The following report was reviewed:
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Monthly Operating Report - December 1989.
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8.0 Reactive Inspection Activities
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8.1 ASCO Solenoid Valves i
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A problem was identified at another nuclear facility concerning operability of ASCO Model NP 8323 solenoid valves (SOVs).
The problem involved a failure of the solenoids that were in.use on main steam isolation valves (MSIVs). The solenoids failed such
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that the MSIVs re-opened after slow closure following plant
cooldown. The cause of the MSIV failure was attributed to sticky j
solenoids. The failure would have prevented MSIV closure in an emergency. Plant operators manually vented air from the MSIV operator supply header to close the valves at the affected
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facility.
This matter was reviewed for applicability at Millstone. A four
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question survey was pievided to licensee management on December 11 and responses were received for all three Millstone units.
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The survey questions submitted to the licensee were as follows:
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1.
Does the plant use ASCO dual coil, Model NP-8323 solenoid valves to operate the main steam isolation valves?
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Does the plant have ASCO NP-8323 valves in other safety related(SR) applications?
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Are ASCO Model 8323 solenoid valves tested (other than with
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the test switch) to identify sticky solenoids?
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What is the. testing frequency of ASCO Model 8323 valves?.
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The survey results for all three Millstone plants were forwarded
to NRC management for review and summarized below.
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MP1 MP2 MP3 P
1. Are ASCO Model NP 8323 used on MSIVs?
YES NO NO 2. Are NP 8323s ia other SR uses?
NO NO NO
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3. Are tests performed to ID sticky SOVs?
YES N/A N/A 4. What is the test frequency for the SOVs? QTR _N/A N/A
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Millstone 1 reported that the SOVs are used on.the.MSIVs.
Based on a review of the Millstone 1 FSAR, Section 5.4, the inspector noted each of the-eight main steam isolation valves are operated by two ASCO solenoid valves which control the operation of the pilot valve to direct air pressure to and vent air from the main valve operating piston. One SOV is powered from 120.VAC and one-is powered from 125 VDC - both vital power supplies.
Energizing either SOV pressurizes the operating chamber of the. pilot to open the MSIV.
De-energizing both SOVs vents the-pilot valve chambers and aligns a pilot valve. spool to pressurize'the top of the main valve piston and vent.the underside.
The MSIV closes by the combined force-of the air pressure and the main valve-spring.
As indicated above, both SOVs must be de-energized for the MSIV to shut.
A loss of power to one SOV does not affeet the MSIV. A loss of power to both S0Vs or a loss of air operating pressure will cause the isolation valve to shut. The MSIV is shut by spring pressure alone if air pressure is lost.
The licensee reported that ASCO Model NP-8323 S0V operability is
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proven during the quarterly test of the MSIVs when the valves are stroked fully closed in less than 5 seconds. The licensee reported that there have been no failures of the type reported at the other facility since the Model NP-8323 S0Vs were installed at i
Millstone 1 in 1983.
The inspector had no further comment on this item. No inadequacies were identifie..
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9,0 Management Meetings
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Periodic meetings were held with station management to discuss inspection findings during the inspection period. A summary of findings was also discussed at the conclusion of the inspection. No proprietary information was covered within the scope of the inspection.
No written material was given to the licensee during the inspection period, i
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