IR 05000245/1986019
| ML20213G087 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 11/12/1986 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20213G069 | List: |
| References | |
| 50-245-86-19, 50-336-86-21, NUDOCS 8611170319 | |
| Download: ML20213G087 (21) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
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Report No:
50-245/86-19; 50-336/86-21 Docket Nos:
50-245/50-336 License Nos.
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Licensee:
Northeast Nuclear Energy Company Facility:
Millstone Nuclear Power Station, Waterford, Connecticut
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Inspection at: Millstone Units 1 & 2 Dates:
September 30, 1986 through November 3, 1986 Inspectors:
Theodore A. Rebelowski, Senior Resident Inspector
i Geoffrey E. Grant, Resident Inspector Alan Finkel, Lead Reactor Engineer Approved:
88e C. b M Eu n[/2[N E. C. McCabe, Chief, Reactor Projects Section 3B Date Summary:
Report No. 50-245/86-19; 50-336-21 (September 30 to November 3,1986).
Sco e: Routine NRC resident inspection (268 hours0.0031 days <br />0.0744 hours <br />4.431217e-4 weeks <br />1.01974e-4 months <br />) and Regional Electrical Lead ng neer inspection (13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />).
At Unit 1, safety inspections and observations
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of maintenance were performed. At Unit 2, refueling outage inspection included refueling operations, local leak rate testing, and safety valve testing.
Results: No unacceptable conditions were identified.
Four engineered safeguards actuations occurred at Unit 2 during this inspection.
Two of these were due to personnel error; two were due to radiation monitor problems.
The only effect was to isolate containmment purge ventilation for a short time in each case.
These actuations will be reviewed during the next Systematic Assessment of Licensee Per-
formance (SALP).
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8611170319 861112
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TABLE OF CONTENTS PAGE
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1. ' Persons Contacted....................................................
2.
S umma ry o f Fac i l i ty Ac ti v i ti e s.......................................
3.
Licensee's Action on Previously Identified Items.....................
4.
Engineered Safety Feature Actuation - Unit 2.........................
5.
Emergency Diesel Generator Reliability - Unit 2......................
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6.
Stack Flow Rate Monitor Inoperability - Unit 2.......................
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7.
Refueling Mode Pre requisites Verification - Unit 2..................
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Reactor Coolant Pump (RCP) Operation - Unit 2........................
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9.
Electrical Buswork Insulation Degradation - Unit 2...................
10.
Anticipated Transient Without Scram (ATWS) - Recirculation Pump Trip
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(RPT) System Inspection - Unit 1.....................................
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11.
Main Steam Safety Valves - Unit 2....................................
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12.
Licensee Event Report Review.........................................
13.
Cold Weather Preparations - Units 1 & 2..............................
14.
dore Alteration Evolution Control - Unit 2...........................
15.
Outage During Reduction in Power - Unit 1............................
16.
Local Leak Rate Testing..............................................
17.
Unit ~2 Refueling Activities..........................................
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18.
Decontamination of Steam Generator Channel Heads.....................
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19..Hanagement Meeting...................................................
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I DETAILS 1.
Persons Contacted s
Mr. W. C. Romberg, Station Superintendent Mr. S. Scace, Unit 2 Superintendent Mr. J. Stetz, Unit 1 Superintendent Mr. J. Kelley, Station Services Superintendent The inspector also contacted other licensee employees including members of the Operations, Radiation Protection, Chemistry, Instrument and Control, Maintenance, Reactor Engineering, Security and Training Departments.
2.
Summary of Facility Activities Unit 1 - Unit I has been essentially at 100% power throughout the report period.
On September 30, scram solenoid valve 38-19-117 failed with CRD 38-19 changing position from 48" to 0".
'The solenoid was replaced and the rod was restored to the correct position without incident.
On October 14, the "B"
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Channel Reactor Protection System tripped due to a spiked channel 5 APRM.
Channel 5 was placed on bypass.
The cause was found and the APRM was returned to service in accordance with the Technical Specifications.
Power reductions due to condenser leaks and stop valve testing occurred on October 9,15,17, 25 and November 1.
The October 9 power reduction was to repair a steam leak in the condensate drain system and is described in paragraph 15 of this report.
Unit 2 - Unit 2 previously had entered a refueling outage on September 20.
The fuel shuffle occurred from October 10 to 20.
Chemical cleaning was per-formed on the steam generators with a 10R to SR reduction in radiation fields.
Hydrolazing was performed and Eddy Current Testing is underway on steam genera,
tor No. 1 tubes.
Preliminary indications are that the tube sleeving which will be required will extend the outage by about 2 weeks.
3.
Licensee's Action on Previously Identified Items (Closed) 50-245/86-04-01; 50-336/86-04-01 (IFI) Measurement Control Evaluation, Nonradiological Chemistry.
On completion of the analyses of water samples l.
by the licensee and Brookhaven National Laboratory, an evaluation was per-formed.
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MILLSTONE Units 1 and 2 Split Samples BNL Millstone i
Boron (ppm) SBLC-YA 25,400 25,560 1 112
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Ammonia (ppb) Steam Generator 2 117 1 0 110 1 10 (two samples) Steam Generator 2 118 1 0
Chloride (ppb) Steam Generator 1 11.2 19.3 1 1.72 (two samples) Steam Generator 1 10.0 The analytical comparisons were acceptable.
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4.
Engineered Safety Feature Actuations - Unit 2 a.
At 2:50 pm on September 29, 1986 a Containment Purge Valve Isolation was activated when power to the Engineered Safety Feature Actuation System
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(ESAS) Channel "C" cabinet was inadvertently secured.
ESAS channel "C" is powered from 120 VAC Vital Instrumentation Panel 2-VIAC-3 which has a normal power supply from #3 Inverter and an alternate power supply from 120 VAC Non-vital Instrument Panel 2-IAC-1.
Static Switch VS3 controls the power supply selection to 2-VIAC-3.
At the time, 2-VIAC-3 was being powered by its alternate supply (2-IAC-1) while the normal supply (#3 Inverter) was tagged out for maintenance.
While hanging a production test control tag, an operator accidently opened the Static Switch (VS3)
alternate supply input breaker.
That caused a complete loss of power to 2-VIAC-3 and concurrent loss of power to ESAS channel "C".
The Con-tainment Purge Valve Isolation circuit, using a one-out-of-four (1/4)
trip logic, initiated a containment purge valve closure.
Power was re-gained and the containment purge was restarted within five minutes.
The personnel error was addressed by licensee management and corrective ac-tions included cautioning the operator, discussions with shift crews, and circulation of a Plant Incident Report (PIR).
s b.
At 4:37 am on October 10, 1986, an automatic actuation of ESAS occurred resulting in a Containment Purge Valve Isolation.
The actuation was caused by a high radiation signal from a containment radiation monitor.
The signal was initially attributed to a random noise spike.
Subsequent licensee investigation found the radiation monitor had failed due to water intrusion.
Due to recurrent overheating problems, forced cooling air had been directed at the radiation monitoring unit to extend its service life and reduce repetitive maintenance.
The cooling air caused internal condensation which resulted in water intrusion and failure of the beta scintillation detector.
The unit was repaired, calibrated and returned to service.
The forced air cooling was discontinued.
The radiation monitor's heat susceptible component (roots blower unit) is scheduled for replacement with an improved unit (rotary vane type com-pressor) during the current outage, c.
At 2:34 am on October 29, 1986, an automatic actuation of ESAS occurred resulting in a Containment Purge Valve Isolation.
The actuation was caused by a high radiation signal from a containment radiation monitor.
Investigation by the licensee indicated that the signal was caused by a random noise spike, d.
At 1:40 pm on October 29, 1986, a Containment Purge Valve Isolation was activated when power to ESAS Channel "A" cabinet was inadvertently secured.
ESAS Channel "A" is powered from 120 VAC Vital Instrumentation Panel 2-VIAC-1 which has a normal power supply from #1 Inverter and an l
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alternate power supply from #5 Inverter.
Inverter testing was in pro-gress and a personnel error resulted in both the normal and alternate power supplies to 2-VIAC-1 being de-energized.
In all four cases, equipment functioned as required and containment purge was quickly restored.
No other ESF actuations occurred.
The inspector had no further questions.
5.
Emergency Diesel Generator Reliability-Unit 2 Based upon the planned licensee actions to improve the reliability of the Unit 2 "A" Emergency Diesel Generator (EDG) identified in Inspection Report 50-336/86-09, the resident inspector conducted a follow-up inspection to deter-mine action item status.
The licensee had been in the process of revising OP2346A, " Emergency Diesel Generator Operation" to place limits on EDG opera-tion during no load conditions in order to avoid scavenging air blower de-gradation / failure.
The "A" EDG has since undergone its refueling cycle re-furbishment/ maintenance, during which a vendor modified scavenging air blower was used to replace the old blower.
(The Unit 2 "B" EDG and the Unit 1 EDG already have modified blowers.) The modified blowers have larger internal clearances to avoid overheating during extended no load / low load operation.
Fairbanks-Morse Service Information Letter Volume A Issue 8 dated July 14, 1986 removes the maximum no-load running time for an EDG equipped with a modified blower.
Based on this information, the licensee has decided that
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revising OP 2346A is no longer necessary.
However, as good engineering prac-tice, the procedure retains a caution to minimize no-load operation.
Additionally, the licensee had previously determined that an analysis would be conducted of the desirability of retaining the Safety Injection Actuation Signal (SIAS) EDG start signal.
Currently, the EDGs automatically start upon r M ipt of either a SIAS or a Loss of Normal Power (LNP) signal.
The SIAS start is anticipatory and, if not accompanied by an LNP, the EDGs would start and run unloaded. With the original blower design, prolonged no-load opera-tion was detrimental to EDG reliability.
Although use of the modified blower lifts EDG no-load operation restrictions, the licensee has concluded that re-moval of the SIAS start signal will still be beneficial to EDG reliability.
Evaluations of the proposed change by the licensee and Westinghouse indicate that removal of the SIAS auto start signal does not impact the Design Dasis Accident (DBA) analytical assumptions.
The DBA calculations assume a loss of offsite power (EDG start) at the beginning of the transient for large break LOCAs and at the time of reactor trip for small break LOCAs. Accordingly, the licensee plans on removing the EDG SIAS start signal during the current outage.
The resident inspector will review Unit 2 blower modification and retest efforts during routine inspection.
6.
Stack Flow Rate Monitor Inoperability - Unit 2 The Unit 2 Main Exhaust Stack Flow Monitor instrumentation provides a hard copy record of stack flow as well as flow switch interlock signals to the Fuel Handling Area and Radwaste ventilation supply fans.
On March 17, 1986 the
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flow monitor was declared inoperable due to a failed " bell assembly" in the flow detector element portion of the monitor.
Due to the age and scarcity of this monitor (Foxboro D/P Model 40), a replacement assembly was not in-stalled and calibrated until June 11, 1986.
Plant Technical Specifications allow continued effluent releases via this pathway provided best efforts are made to repair the instrument, if the flow rate is estimated once per four hours.
If efforts to restore instrument operability within thirty days are unsuccessful, then Technical Specification 3.3.3.10.a requires that the fail-ure to correct the inoperability in a timely manner be explained in the next Semiannual Effluent Report.
Although other required action statement compen-satory measures were initiated, the licensee did not explain the extended in-operability of the stack flow monitor in the issued Semiannual Effluent Report covering the period of January - June,1986.
The primary cause of the report-ing failure was a deficiency in the licensee's program that tracks Technical Specification Limiting Conditions for Operations (LCOs) and action statement entries.
The procedure adequately identified LCOs but failed to identify all action statement requirements for conditions that had no time limit.
The licensee has recently instituted procedural changes to correct this deficiency.
Additionally, the licensee intends to revise the current report to include the missing information.
No safety inadequacies were identified in this case.
The resident inspector will monitor licensee corrective actions during routine inspection activities.
7.
Refueling Mode Pre-requisites Verification-Unit 2 The resident inspector conducted sampling inspections of Technical Specifica-tion required surveillances and plant conditions to verify that prerequisites were met prior to entering Mode 6 (Refueling) and prior to the commencement of core alterations.
The inspector found a consolidated and well coordinated licensee program in effect to ensure mode change and core alteration prere-quisites were met.
Areas inspected included:
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Minimum allowable Reactor Coolant System and refueling canal boron con-centration determination.
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Source range neutron flux monitor operability.
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Reactor decay time determination.
Containment penetration integrity.
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Refueling communications.
Shutdown cooling system operability.
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Containment radioactivity monitor operability.
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Containment purge valve isolation system operability.
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Spent fuel pool area ventilation line-up.
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The inspector identified no deficiencies and had no further questions.
8.
Reactor Coolant Pump (RCP) Operation-Unit 2 The licensee was notified on September 5, 1986 by letter from Westinghouse Electric Corporation, Water Reactor Division, of a potential unreviewed safety question concerning an inconsistency between plant Technical Specifications and the safety analysis relative to RCP operation in Modes 3, 4 and 5.
During a review of the current plant safety analysis, Westinghouse noted t it plant Technical Specifications (TS) allowed more flexibility in RCP opera, son then did the safety analysis.
Specifically, TS 3.4.1.2 requires that both reactor coolant loops and at least one pump in each loop be operable during Mode 3 (only one RCP is required to be operating).
Similarly, plant operation in Modes 4 and 5, TS 3.4.1.3 requires the operability of various combinations of reactor coolant loops, RCPs, and shutdown cooling loops (as little as one shutdown cooling loop is required to be operating).
In contrast to these specifications, the current safety analysis assumes all four RCPs are operat-ing for various accident scenarios including Control Element Assembly (CEA)
ejection and withdrawal from subcritical.
According to 10 CFR 50.36, the assumptions in the safety analysis and the Technical Specifications must be consistent in order to assure that the plant is operated in a manner that is bounded by the safety analysis.
Since the Technical Specifications allow fewer operating RCPs than the safety analysis assumes, the margin of safety may be reduced.
That is an unreviewed safety question in accordance with 10 CFR 50.59.
Upon notification, the licensee confirmed the inconsistency and made the re-quired 10 CFR 50.72 report.
A written follow-up report is forthcoming.
The licensee has instituted interim administrative measures to correct this prob-lem including night order entries and tagging open CEA trip breakers unless four RCPs are operating.
The final solution is still under licensee review and will be monitored by the resident inspector during routine inspection activities.
9.
Electrical Buswork Insulation Degradation - Unit 2 On October 6, 1986 during routine outage inspection and maintenance of 6.9Kv switchgear, the licensee identified excessive cracking and splitting of the
"NORYL" insulating sleeves which cover the main bus bars.
The sleeves are a high temperature thermoplastic which provides electrical insulation.
Al-though not an immediate problem, the cracking and splitting of the sleeves could become a hazard.
If degradation of the sleeving ex?osed ufficient bus bar area, phase-to phase arcing could occur.
If the sleeving partially peeled off the bus bar and contacted switchgear internals, damage to the bus bar or a fire could result.
Although the original findings were related to the non-safety 6.9Kv buses (25A and 25B), similar sleeving degradation was identified l
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on a Category 1, 4160V safety bus (24C) during continuing licensee inspection.
The remaining 4160V safety and non-safety buses are scheduled for inspection during the current outage.
This potential failure had been previously identified by the equipment vendor (General Electric) and disseminated to the industry via various service in-struction and advice letters.
Vendor investigations have shown that the thermoplastic sleeve insulation (NORYL), while normally stable and suitable for this application, may undergo stress cracking if significant stresses and any of several petroleum-based greases, plasticizers, paint thinners, indus-trial cleaning fluids, or chemical contaminants are present.
The stresses may be heat, vibration, or fabrication induced.
Chemical contamination may result from cleaning or maintenance involving buswork connections.
The cur-rent sleeving degradation appears to be related to the use of a noncompatible bus joint compound (grease).
The cracking generally appears in proximity to joints containing the noncompatible grease and is generally absent where the grease is absent.
The vendor currently recommends the use of only one type of joint compound with no substitutions, having found that other types are not compatible with the sleeving.
Also, the use of cleaning agents other than denatured alcohol is not recommended.
The licensee is currently replacing all of the bus bar sleeving on 6.9Kv buses 25A & 25B and on 4160V safety bus 24C.
Based on subsequent inspections, the licensee intends to replace any cracked sleeving and any undamaged sleeving in proximity to areas where noncompatible joint compound is found.
The lic-ensee is following vendor recommendations pertaining to the use of an allow-able joint compound and cleaning agent during the replacement process.
The resident inspector will continue to monitor the inspection and repair process during routine inspection.
10.
Anticipated Transient Without Scram (ATWS)-Recirculation Pump Trip (RPT)
System Inspection-Unit 1 a.
Background On February 21, 1980 the NRC issued a Confirmatory Order requiring the installation of an RPT system by December 31, 1980.
This RPT was to be a diverse means (separate from the Reactor Protection / Trip System) of making the reactor subcritical should there be an ATWS.
The ATWS-RPT modification was accomplished on Unit 1 during the 1980 refueling outage.
The modification de-energizes the pump motors by opening the associated Motor-Generator (MG) set generator field breaker.
A second shunt trip coil was installed in each MG set field breaker and, when used with the existing shunt trip, provides a one-out-of-two shunt trip for the ATWS-RPT function.
During this inspection period, NRC specialist inspection was conducte ~'
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b.
System Design The ATWS-RPT system at Unit 1 is an energized to operate system with logic arranged such that two-out-of-two ATWS signals (two pressure or two level signals) will trip a GE AK-F-2-25 breaker.
Each breaker has dual trip coils and, when tripped, opens the field in the associated pump MG set.
The ATWS signals are high pressure (1150 psig) and/or low reac-tor water level (-48").
The trip circuits are powered from Division A and B 125VDC power sources.
The ATWS level and pressure sensors are different from those used in the reactor protection system.
They also are environmentally qualified and maintained on the licensee's list of safety-related equipment.
The logic and control for RPT can be tested on-line.
The breakers are tested when the reactor is off-line or during a refueling outage.
The selection of trip set points, training instructions, and procedures are such that inadvertent actuations will be minimized.
Emergency operating procedure E0P572, " Reactor Power Control Emergency Operating Procedure," provides guidance to the operators in the event the recirculating pump fails to trip on high pressure or low water level trip signals.
This emergency operating procedure instructs the operator to manually scram the reactor and trip the recirculating pumps.
The transients from tripping the recirculation pumps are analyzed in the facility final safety analysis report (FSAR).
The consequences of these transients are within the limiting transient analysis in the FSAR.
The licensee's preliminary analysis indicates that the recirculation pump's trip unreliability factor is 6.38E-4/ reactor year.
The reactor protection trip system design at Unit 1 was found consistent with 10 CFR 50.62 (ATWS Rule).
The design and operating procedures are based on guidance developed by General Electric and submitted to the NRC.
c.
Use of GE-AK-F-2-25 Breakers The GE-AK-F-2-25 breaker trip coil trips the field of the generator coil of the motor generator set if it receives an ATWS signal.
The licensee has two such breakers, one for each MG set.
A review of the Production-
Maintenance Management System (PMMS) and breaker maintenance cards veri-fied that no failures of these breakers are documented for Unit 1.
d.
System Surveillance The RPT surveillance test requirements are listed in the PMMS system and are performed per procedures as specified in a letter to the NRC dated February 21, 1980, titled Modification of Operating license, and in NRC Generic Letter 83-28.
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The frequency of system testing is once per refueling cycle.
The sur-veillance of the instrumentation and iogic system is performed on a quarterly basis.
There have been no failures of RPT sensors, transmit-ters, or breakers in the system to date.
e.
System Maintenance The licensee has a formal maintenance program which includes both cor-rective and preventive maintenance activities and is documented in the PMMS.
The licensee maintains the system component history in the PMMS and on the breaker maintenanca cards.
Part History, corrective actions, quality control, inspection status, and management approvals are documented in the PMMS.
At the present time, trending is being performed on selected components, but nothing specific-ally is being performed on the RPT system or its components.
Preventive maintenance is performed on the RPT system during refueling outages.
f.
System Reliability Single Failure Criteria - In that the sensors, transmitters, sensing lines, power supplies, cables and instrumentation racks, and trip coils are redundant, the system complies with NRC accepted single failure pro-tection measures.
The redundant trip coils of the GE AK-F-2-25 breaker will trip on a pressure trip from A and C channels or a level trip from B and D channels.
g.
Quality Assurance A quality assurance program in conformance with the requirements of 10 CFR 50, Appendix 8 was applied to the RPT design and components of the system including the breakers.
h.
Equipment Qualification The sensors, instrumentation, relays, switches and cables have been qualified to assure that the RPT will perform its functional operability under conditions relevant to the postulated ATWS.
The instrumentation racks are seismically installed and meet the design requirements for the site location.
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Channel Independence All components used to trip the recirculation pumps are independent and separate from components that provide the reactor protection function.
Although the sensors for both the RPT and the RPS are located on the same instrumentation racks, there are redundant racks with the sensors ar-
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ranged so that a failure of a rack or of an instrument sensing line will not prevent an RPT.
Diversity between the RPT and the RPS is achieved by design and was verified by inspection.
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System Reliability The licensee has the components of the RPT system in the preventive and corrective maintenance program with the data reviewed by management.
This data (PMMS) is also available to the reliability engineer.
At this time there is no formal trending program in operation.
Trending is being performed on a selected component basis.
The failure rates for the RPT systems are defined in the Probabilistic Safety-Study, Volume 4 for Unit 1.
There are no design changes issued to increase the reliability of the RPT system at this time.
The inspector had no further questions on the ATWS-RPT trip.
11.
Main Steam Safety Valves - Unit 2 References:
a.
IE Information Notice No. 86-56 Reliability of Main Steam Safety Valves.
b.
IE Information Notice No. 86-05 and 86-05 Supplement 1.
c.
Unit 2 Station Procedure 2730 B, Main Steam Safety Valve Test.
d.
ASME Power Test Code 25.3 - 1966 e.
Millstone Unit 2 Technical Specification 4.7.1.1.
f.
Licensee Instruction for Installation and Maintenance of Main Steam Safety Valves Type 3700.
j The licensee performed a " simmer" test of Main Steam Safety Valves on Septem-
ber 20, 1986 to verify the Limiting Condition for Operation that all main stea.m line code safety valves shall be operable (T.S. 3.7.1.1).
The plant was operating in mode 3 (hot standby), at 0 percent power, 532 degrees Fah-renheit, and 2257 psig.
Nine (9) of the sixteen (16) valves failed their first test.
a.
Test Format The licensee conducts this test with a Hydroset unit that aids in reduc-ing spring pressure thus enabling the individual main steam safety valves to lift without raising steam line pressure.
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Test Results The test results for the first test of each of the sixteen valves are listed below:
MAIN STEAM SAFETY VALVE PRESSURE SETPOINT ALL PRESSURES ARE IN GAUGE PRESSURE MILLSTONE MANUFACTURER AS FOUND AS LEFT VALVE SERIAL SETPOINT SETPOINT SETPOINT NUMBER NUMBER PRESSURE PRESSURE PRESSURE 2-MS-239 BN 4976 1035 1 10 1039 1029 2-MS-240 BN 4972 1030 1 10 1024 1024 2-MS-241 BN 4968 1U10 1 10
- 1032 1011 2-MS-242 BN 4964 990 1 10
- 1008 993 2-MS-243 BN 4974 1035 i 10
- 1054 1038 2-MS-244 BN 4970 1020 1 10 1028 1028 2-MS-245 BN 4966 1000 1 10 1008 1005 2-MS-246 BN 4962 985
- 973 984 2-MS-247 BN 4961 985 i 10
- 973 984 2-MS-248 BN 4975 1035 i 10
- 1049 1029 2-MS-249 BN 4965 1000 1 10 996 995 2-MS-250 BN 4971 1030 1 10 1023 1028 2-MS-251 BN 4969 1020 1 10 1013 1011 2-MS-252 BN 4967 1010 1 10
- 929 1003 2-MS-253 BN 4973 1035 i 10
- 1019 1031 2-MS-254 BN 4963 990 1 10
- 1019 997
- 0ut of setpoint range.
The licensee's test criteria allows two test attempts with one satisfac-tory valve setpoint test representing a satisfactory test.
Three main steam safety valves did meet acceptance criteria on the second test and were considered acceptable.
These valves are 2-MS-241, 2-MS-242 and 2-MS-243.
c.
NRC Inspector Review of Test Results The licensee method of evaluation of an acceptable valve appears non-conservative in that numerous failures can occur with only the final setpoint required to be satisfactory to achieve a successful test.
An example of this is documented in 2-MS-244 testing which is listed as satisfactory.
2-MS-244 (1020+-10psig) had the following test sequence:
First test 1028 psig - test satisfactory The licensee then adjusted the spring tension to lower pressure with the folicwing results:
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PSIG Results Adjusted Out of Range 2nd test 1009-1 3rd test 1035 Tension Change
+5 4th test 1049 Tension Change
+19 Sth test 1040 Tension Change
+10 6th test 1032 Tension Change
+2 7th test 1028 passed Thus, after five failures after spring adjustments, a single acceptable setpoint test meets the acceptable criteria.
d.
Procedural Changes Discussion with licensee management determined that a procedure change will be made to require a minimum of two successive satisfactory simmer test points.
This procedural change is to be made prior to entering into mode 3.
All main steam safety valves that may require adjustment would then fall under revised procedure criteria.
e.
Licensee Further Actions The licensee has attempted to pinpoint the cause of the experienced main steam safety valve setpoint drift by monitoring main steam safety valve spring temperature, thus enabling them to duplicate temperatures during subsequent testing.
They also have increased the accuracy of pressure gauges that had previously contributed to total error.
Based on licensee's procedural changes, the inspector had no further questions on test criteria.
Implementation of the procedure change will be reviewed during routine inspection.
12.
Licensee Event Report Review LER 50-336/86-008-00 - Failure of Main Steam Safety Valves The licensee has issued an informational LER that describes the failure of six code safety valves.
The licensee Table 1 indicates nine failures.
This was discussed with the licensee; a clarification will be issued to this LER.
Main Steam Safety Valve testing is discussed in paragraph 11 of this report.
13.
Cold Weather Preparations - Units 1 & 2 The licensee has previously identified, in their correspondence in response to IE Bulletin 79-24, problems that have been encountered during extreme cold weather.
Procedural changes, hardware changes that require heat-tracing, and increased frequency of inspection by operations personnel were addressed.
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12 During this report period, outdoor temperatures of 20* Fahrenheit have been encountered.
An inspection of freeze protection was conducted.
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Unit 1--Operations Plant Equipment Check Log 1-0PS-10.09 requires that, when
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outside temperature is <35*F, actual temperatures for such equipment as the Demineralized Water Storage Tank, Condensate Storage Tank, Waste Surge Tank, Domestic Water Tank, Strip Heaters, and "A" and "B" Fire Tank levels be re-
corded daily.
No recent freeze-ups have been identified.
Unit 2--The Operations Plant Equipment Check Log Procedure 2669 requires that power on heat tracing equipment be inspected on each watch.
During the in-
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spector's tour of the condensate, RWST, and Primary Water Tank enclosures, a number of circuits were found deenergized and lacking heat tracing.
The licensee stated that these circuits were under repair.
Discussions with maintenance-electric indicated that the systems were disabled and under work
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orders.
No safety inadequacy was identified, but the PE0 log failed to indi-cate these system conditions.
Discussions with management were held; the licensee will review logging practices.
This will be reviewed again during
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routine inspection.
4 14.
Core Alteration Control - Unit 2
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a.
Plant Status f
The Unit completed refueling operations on October 20, 1986 and was
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awaiting an outage activity window that would allow establishment of
plant conditions necessary to reassemble the reactor vessel.
On October 27, 1986, with the plant in Mode 6, the "A" Emergency Diesel Generator (EDG) was declared inoperable at 2:10 pm in order to conduct restoration maintenance on the Service Water System. The "B" EDG was already in-operable while undergoing general outage preventive maintenance.
Subse-
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quent to Service Water repairs, the "A" EDG was retested and restored to operable status at 9:26pm on October 27, 1986.
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b.
Core Alteration
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In order to support commencement of the reactor vessel reassembly, lic-
ensee personnel conducted a final visual core inspection on October 27,
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1986 at approximately 3:00pm.
Upon completion of the inspection at approximately 4:00pm, licensee personnel removed a lighting assembly
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which had been suspended inside the reactor vessel to aid visibility during core verification and inspection.
At that time the licensee con-
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servatively considered the movement or manipulation of any apparatus within the reactor pressure vessel (with the vessel head removed and fuel
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in the vessel) as a core alteration.
In this case, the licensee's de-
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finition included the lighting assembly.
Therefore, a core alteration took place by definition when licensee personnel removed the lighting i
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assembly from the reactor vessel and placed it in the refuel pool.
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evolution was conducted with a reactor engineer and the Technical Speci-fication 6.2.2 required Senior Reactor Operator in attendance and super-vising the movement.
c.
Technical Specification Requirements The resident inspector examined Technical Specification action statements, plant status, operating logs, and documentation of plant evolutions to determine the appropriateness, compatability, and acceptability of lic-ensee actions occurring while both EDGs were inoperable.
Technical Specification (TS) 3.8.1.2 requires at least one EDG to be operable when in Modes 5 and 6.
If no EDGs are operable, then the TS 3.8.1.2 action statement requires the suspension of all operations involving core al-terations or positive reactivity changes until one of the EDGs is re-stored to operable status.
The resident inspector found that licensee personnel removed the lighting assembly from the reactor vessel when both EDGs were declared inoperable and core alterations were prohibited, d.
Safety Significance Discussions with the licensee identified a definite awareness of the potential conflicts and requirements that arise when both EDGs are in-operable.
The licensee was also well aware o' the plant conditions re-quired to support a core alteration.
These evolutions were discussed during various management and Plant Operations Review Committee (PORC)
meetings.
Initial indications are that there was a lack of communication among licensee personnel concerning whether the "A" EDG was returned to operability when the Service Water repairs and restoration were complete (approximately 3:30pm) or when the EDG was tested by starting at 9:26pm.
The literally proper action would have been to prohibit the evolution until the "A" EDG was tested and returned to operable status.
Because the lighting assembly was suspended well above the core and because it was very improbable that it could have come in contact with and/or moved a core element during removal, the safety significance of this evolution is considered minimal.
Subsequent to completion of the evolution and after discussions with the resident inspector, the licensee analyzed the definition of a core alteration and found it to be overly conservative.
Hence, the licensee currently maintains that moving the lighting assembly did not consititute a core alteration and therefore the prerequisite plant conditions (one operable EDG per TS 3.8.1.2) were not required.
In this specific case, the inspector concluded that the licensee had not fully complied with administrative requirements which exceeded those required to comply with NRC regulations.
However, this situation demon-strates diminished licensee control and lack of effective coordination during the evolution.
The resident inspector discussed with licensee management the importance of adherence to established procedures as the method for evolution control vice post-evolution re-analysis. The resi-dent inspector will review licensee corrective actions, coordination activities, plant control, and similar evolutions during routine inspec-tions.
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15.
Reduction in Power - Unit I a.
The licensee downpowered to 47% at 0700 hours0.0081 days <br />0.194 hours <br />0.00116 weeks <br />2.6635e-4 months <br /> on October 9, 1986 to allow corrective maintenance on the following:
(1) A/B Condensate Outlet Crossover Valve Motor Operator.
(2) Replacement of Feedwater Relief Valve.
(3) Rework Steam Traps on Isolation Condenser.
(4) Replacement of parts on Bean Valve-Turbine on front standard.
(5) Feedwater Regulator Valve Positioner Repairs (6) Encapsulation of Steam Drain piping.
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The inspector monitored the following licensee maintenance:
(1) Encapsulation of Steam Drain Piping-B Moisture Separator (1-HD-18A)
The inspector witnessed the installation of a three part encapsula-tion of steam drain piping.
This enclosure envelope was cast steel weighing approximately 500 lbs.
The inspector requested verifica-tion of additional loads.
The licensee had calculated that a sup-port spring range adjustment might be necessary.
The encapsulation did not cause out of range readings and the support spring did not require readjustment.
The inspector had no further questions.
(2)
"A" 1P Heater Water Box Relief Valve Due to continued leakage from relief valve 1-CW-112A, the licensee obtained a relief valve of same configuration except for a change to threaded vs. welded socket attachment to the system.
The new relief valve could not be put in service due to failure to provide double valve protection (approximately 100 psig system).
The in-spector viewed the proposed new area for installation downstream of Eooster Pump No. 2.
The inspector had no further questions in this area.
(3) A/B Condensate Outlet Cross-Over Motor Operator The inspector witnessed the installation of the motor and operator of A/B Cross-Over Valve.
This motor had been rewound and the motor actuator was tested satisfactorily.
The inspector had no further questions.
(4) Radiation Protection During Maintenance The inspector verified proper radiation protection during the re-pairs conducted on:
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(a) A-B Condensate Outlet Cross Over Valve motor replacement.
(b) The installation of new encapsalation casting for "B" Moisture removal drain line 1-HD-18A.
Items verified were prejob briefing, Health Physics personnel area survey during initial entry to perform work, proper clothing for individuals and proper monitoring where overhead radiation levels were 40-60 Mrem / hour with dosimetry required for helmets.
No de-ficiencies were identified.
16.
Local Leak Rate Testing - Type C - Unit 2 The licensee attended a meeting with the Division of Reactor Safety and NRR at Region I on June 4, 1986 to discuss the proposed schedule for the Type A containment leak rate test.
It was determined by the NRR Division of PWR Licensing - B that the proposed schedule for Type A testing was acceptable if the following four conditions were met.
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That a preventive maintenance program for Fisher valves be initiated to include replacement of the T-ring gaskets;
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That traps or screens be provided to prevent debris from entering the sump valve's seat area;
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That local Leak Rate Tests (LLRT) for identified " problem" valves be conducted;
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That NRC Region I be notified of any Type B and/or Type C test results which indicate excessive leakage.
a.
Inspection Status (1) Preventive Maintenance Program for Fisher Valves The licensee has instituted a preventive maintenance program to replace Fisher valve T-ring gaskets.
The inspector witnessed the removal of containment isolation valves 2-RB-28-2A, 2-RB-28-3A, and 2-RB-28-1A on the Reactor Building Closed Cooling Water System.
New "T" rings, which are the valve seating gaskets, were being in-stalled.
No deficiencies were identified.
The program to complete the installation of new "T" rings will be reviewed during a subse-quent inspection.
(2) New Debris Traps Traps or screens to prevent debris from entering sump valve seat areas are under licensee review.
This item will be inspected during a subsequent inspection.
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(3) Local Leak Rate Testing The inspectors have witnessed the testing of several identified problem " valves," including test of containment purge valves 2-AC-5, 2-AC-6 and retest of valves 2-SSP 16.1 and 2-CH-506.
Valves 2-SSP 16.1, 2 AC-5 and 2AC-6 remain problem valves due to their failure to fall within the specified acceptance criteria.
These valves were repaired.
A subsequent inspection in this area is scheduled.
(4) Notification to Region of Type B & C Test Results which Indicate Excessive Leakage The licensee notified the resident inspector that a Licensee Event Report will be issued to document excessive leakage identified dur-ing this outage.
b.
Inspector Review of Procedures The inspector review of LLRT special procedure 3612.4.1 Type C indicates that the licensee strokes valves prior to testing.
10 CFR 50 Appendix J prohibits exercising valves prior to as-found testing.
The licensee has identified his reasons for stroking as follows.
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Piping systems must be drained and valves must be opened to accomp-lish this task.
To ensure normal closure, stroking by means of MOV control ensures
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no manual torquing has been performed.
The resolution of the method of testing in an as-found condition will be reviewed by regional specialist inspectors and NRR.
The resident inspector will continue to follow licensee actions in this area.
17.
Refueling Activities - Unit 2 a.
General This inspection was conducted to ascertain whether the licensee's ad-herence to the pre-refueling activities specified in the technical specifications (TSs) have been completed and whether refueling activities are being controlled and conducted as required by TSs and approved pro-cedures.
A review of refueling mode prerequisites is discussed in para-graph 7 of this report.
b.
References OP 2209A Refueling Operation Rev. 11
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OP 2303 Fuel Handling System Rev. 14
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OP 22098 Neutron Source Handling Rev. 4
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EN 21001 Special Nuclear Material Control Rev. 7
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EN 21008 Refueling Worklist Administration Control Rev. 3
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SP 21025 Spent Fuel Pool Criticality Requirements Rev. 0
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c.
Findings (1) Procedure Review
Licensee procedures were found acceptable in that they did have
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specific criteria to meet Technical Specifications.
Examples re-
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i viewed were OPS Form 2209A 1 through 9 which verify plant system
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conditions, count rate data, pre-flood-up reactor pool checklist, refueling preparation checklists, refueling machine operational check, transfer system preoperational checks, spent fuel pool plat-form crane preoperational check list, communication preoperation checklist, alignment of refueling machine and fuel cask crane check.
Procedures were detailed and encompassed all phases of refueling.
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(2) Pre-refueling Activities The following items were verified through observation or data review:
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The licensee had implemented controls for the conduct of re-fueling operations and maintaining the control of plant condi-tions.
Discussions were held with cognizant licensee personnel about 1/M plots and SR0 adherence to administrative controls
in the control room, containment and spent fuel area.
Review i
of the responses on responsibilities and on the understanding of responses to casualties showed acceptable knowledge.
The technical specification requirements for surveillance
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testing for source range neutron flux monitoring (TS 3.9.2)
i and channel functional test was completed on October 10.
Boric acid samples were completed and found satisfactory (TS 4.9.17, 4.9.16.2).
The following check sheets were verified complete prior to fuel
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movement:
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Preparation for Core Alteration Checklist 2209C-1.
Weight Reference Sheet for Lightweight CEA Handling Tool.
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Prerequisite Sign Off Sheet - Ops Form 2209A-1 which ad-
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dresses Storage and Inspection of new fuel.
-The Technical Specifications that satisfy various phases
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of refueling include:
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T.S. 3.9.6 and 3.9.7 - verification of load capacitor
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and interlocks associated with the refueling machines.
The inspector found the licensee program to meet technical specifi-cation requirements to be excellent.
(3) Observations of Fuel Movement Fuel movements occurred betwen October 10 - 20, 1986.
Prior to fuel movement, observations were made in the control room.
Engineering support personnel were on station to monitor 1/M plots, fuel status boards, and fuel movements.
The shift supervisor was knowledgeable of requirements necessary to commence fuel handling.
The inspector witnessed the fuel movements on regular and back shifts in containment and at the spent fuel pool.
All handling was conducted in a manner that was acceptable such as logs of movements, proper personnel in all areas, and proper communications.
Also, areas were free of debris and controlled for entrance of material.
Fuel movements were conducted in an acceptable manner.
The experi-enced personnel, SRO, and engineers were thoroughly familiar with the program and this resulted in a fuel shuffle with no incidents.
No deficiencies were identified.
18.
Decontamination of Steam Generator Channel Heads The licensee has performed steam generator (SG) channel head decontamination by means of chemical and mechanical cleaning.
The licensee instituted this program to reduce radiation levels in order to perform maintenance during outage and thus address ALARA concerns.
The chemical process reduces primary system radioactivity, primarily from Cobalt 58 and 60 in oxide films.
The process involves a preoxidation, neutralization, decontamination and final cleanup using ion exchange beds.
a.
Observation Prior to SG decontamination, the inspectors monitored the following.
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Method of adjustment of penetration fittings to accommodate flush hoses.
Precautions against radiation from steam generator effluent.
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Attachments to covers on steam generator heads.
In addition, the inspectors examined the waste holding tank area, the chemical mixing shed, the booster pump shed, and the ion exchange area.
No deficiencies were identifie _
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The licensee had problems with steam generator flush cover leakage.
Hold tank capacity required interruption of the cleaning process to process waste.
Also, a non-functioning heater was replaced and there were minor spills.
The cleaning resulted in a reduction of approximately one half of the starting levels (from 10R to SR).
Eddy current testing in these areas were in progress at the end of report period.
The inspector had no further questions on this chemical cleanup process.
19.
Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss the findings.
No proprietary information was identified as being in the inspection coverage.
No written material was pro-vided to the licensee by the inspector.
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