IR 05000220/1991020
| ML17056B505 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 11/04/1991 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17056B504 | List: |
| References | |
| 50-220-91-20, 50-410-91-20, NUDOCS 9111180093 | |
| Download: ML17056B505 (34) | |
Text
h U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.;
Docket Nos.:
License Nos.:
Licensee:
91-20; 91-20 50-220; 50-410 DPR-63; NPF-69 Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse,.New York 13212 Facility:
Location:
Dates:
Nine Mile Point, Units 1 and 2 Scriba, New York September 8 through October 5, 1991 Inspectors:
Approved by:
W. L. Schmidt, Senior Resident Inspector R. R. Temps, Resident Inspector R. A. Laura, Resident Inspector W. F. Mattingly, Operations Officer, AEOD X~/rZ(J~4~
~pi q/'q Donald R. Haverkamp, Chief Date Reactor Projects Section No. 1B Division of Reactor Projects Ins ection Snmmar:
This inspection report documents routine and reactive inspections of plant operations, radiological controls, maintenance, surveillance, security, engineering and technical support and safety assessment/quality verification activities.
Results:
See Executive Summary.
91 i 1 180093 91 i 105 PDR ADOCN 05000220 G
XE TIVE UMMARY Nine Mile Point Unit 1 and Unit 2 NRC Region I Combined Inspection Report Nos. 50-220/91-20 and 50-410/91-20 September 8 - October 5, 1991 PPP ':
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this period.
This was evident by the good operator response and management followup to the automatic reactor scram on September 26.
Operators performed well at Unit 2 as indicated when the unit was returned to service on September 26 in a controlled and conservative manner.
Flow instability problems with the reactor core isolation cooling (RCIC) system were identified by the operators and proper actions were taken to eliminate the problem.
Radiolo ical Control:: No program weaknesses were identified as a result of routine inspector tours in radiologically controlled areas.
However, the inspector identified a case where I&C technicians left a puddle of potentially contaminated water unguarded on the floor in the Unit 2 reactor building subsequent to a transmitter venting evolution.
Maintenance:
Safety related corrective maintenance on the number 11 control rod drive pump at Unit
was observed to be well controlled and supervisory oversight was evident.
Troubleshooting and repair of the Unit 2 RCIC system flow oscillations was assessed to be performed in a competent manner.
e'.:2 ill
<<lgfd fly pyl pU
dud assessed to be performed correctly.
However, the inspector identified an unresolved item (220/91-20-01) concerning the inadequate control of the installation and use of a test gage (a temporary modification) to obtain setpoint data of a pressure control valve, in conjunction with the quarterly core spray loop surveillance test.
~ecurtt:
The security department was observed to maintain proper controls over personnel entering the vital area.
However, a security guard was observed by an inspector to be relaxing in a chair in an out of the way location in the plant.
Security management initiated an investigation of this matter, and the results will be available for subsequent NRC inspections.
Fn ineerin and Technical n
ort:
A Unit 1 Appendix J issue concerning leak testing containment spray valves was determined to be resolved.
A Unit 1 unresolved item concerning approval of test data by phone was also closed:
Safet As essment/
nalit Verifi tion: Six Unit 2 licensee event reports (LERs), two Unit 1 LERs, a Unit 1 site operations review committee meeting, and activities of the operating experience assessment groups were reviewed and found to be satisfactory.
TABLE F CONTENT 1.0 SUMMARYOF FACILITYACTIVITIES 1.1 Niagara Mohawk Power Corporation Activities 1.2 NRC Activities............... ~...
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1.2.1 Routine Resident Inspection - Unit 1 and 1.2.2 Inspection and Investigation ofthe August
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Unit 2 13, 1991 Reactor Scram
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2.0 UNIT 2 RESTART ACTIVITIES (71707, 61726, 62703)..............
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2.1 Plant Startup Observations..............................
2.2 Reactor Core Isolation Cooling Surveillance and Corrective aintenance M
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3.0 PLANT OPERATIONS (71707, 71710)
3 ~ 1 Routine Plant Operations Review - Unit 1 3.1.1 Emergency Cooling System Isolation,......
3.1.2 Automatic Reactor Scram Following a Generator 3. 1
~ 3 Safety System Verification 3.2 Routine Plant Operations Review - Unit 2 3.2. 1 Safety System Verification
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Load Reject..
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e 4.0 RADIOLOGICALCONTROLS (71707)......................
4.1 Routine Radiological Control Observati'ons - Units 1 and 2......
7 5.0 MAINTENANCE(62703)
5.1 Observation of Maintenance Activities - Unit 1
8 6.0 SURVEILLANCE(61726)
6.1 Observation of Surveillance Activities - Unit
6.1.1 Core Spray Pump and Valve Quarterly Testing
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7.0 SECURITY AND SAFEGUARDS (71707)............
7.1 Routine Security Observations
- Units 1 and 2......
8.0 ENGINEERING AND TECHNICALSUPPORT (92701)
8.1 Routine Review - Unit 1 8.1.1 (Closed) Violation50-220/91-02-02:
Containment J Water Seal Issue 8.1.2 (Closed) Unresolved Item 50-220/89-81-07
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Spray Appendix
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Table of Contents (Continued)
9.0 SAFETY ASSESSMENT AND QUALITYVERIFICATION..........
9.1 Routine Review - Unit 1.... ~.................. ~....
9.1.1 Review of Licensee Event Reports (LERs) and Special Reports 9.1.2 Review of Site Operations Review Committee Meeting 9.2 Routine Review - Unit 2..... ~......................
9.2.1 Review ofLERs................. ~...... ~....
9.3 Review of Operational Events Assessment Program - Units 1 and 2
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10.0 MANAGEMENTMEETINGS ~............................
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The NRC inspection manual procedure or temporary instruction that was used as inspection guidance is listed for each applicable report sectio DETAILS 1.0 SUMMARYOF FACILITYACTIVITIES 1.1 Nia ara Moh wk Power ration Activitie The Niagara Mohawk Power Corporation (NMPC) operated Unit 1 at near rated power until September 26 when a generator trip caused a turbine trip and, as designed, an automatic reactor scram.
NMPC investigation of the cause of the generator trip led to a discovery that a current transformer used to measure generator phase current flow and to determine the neutral phase current flow had failed.
At the close of the period, the unit remained in cold shutdown as NMPC prepared to fix the current transformer.
At the beginning of the period, Unit 2 remained in cold shutdown following the August 13, 1991, transformer failure, reactor scram, and loss of non-safety related uninterruptible power supplies.
By letter dated September 10, 1991, NMPC certified that it had taken all the corrective actions necessary to return the unit to service (also see section 1.2.2).
On September 19, control room operators began a normal reactor startup, and reactor core isolation cooling (RCIC) testing was completed satisfactorily at 150 psig reactor pressure.
At 500 psig and 935 psig reactor pressure the RCIC system showed unstable responses to controller demand step changes.
Further, because of temperature and radiological conditions at the top of the drywell, NMPC could not complete an ASME code required visual inspection of a RCIC flange which had been disassembled and reassembled during the outage.
To allow correction of these problems, NMPC brought the reactor sub-critical on September 22.
A video camera was installed to allow remote monitoring of the RCIC flange,'nd new governor parts were installed on the RCIC turbine.
The unit then was brought critical again and RCIC testing and the visual inspection of the RCIC flange were completed satisfactorily.
The unit was placed on the grid on September 26 and reached full power on September 30.
1.2 1.2.1 Routine Re ident Ins tion -
nit I and nit 2 The inspection activities during this report period included routine inspection during normal, backshift, and weekend hours by the resident staff. These routine inspections included 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br /> of backshift (evening shift) and six hours of deep backshift (weekend, holiday, and midnight shift) inspections during this period.
Further, coverage was provided by the resident staff for the Unit 2 restart effort as described in section 2.0 below, which included 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> of backshift and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of deep backshift observation.2.2 Ins tion and Inve ti ation f the Au ust
1 1 Reactor cram -Unit 2-On August 13, 1991, followingthe reactor scram and declaration ofa site area emergency (SAE)
an augmented inspection team (AIT) was sent to the site. This inspection was supplanted by an incident investigation team (IIT)on August 16, 1991. During that time NMPC management had agreed with NRC management to keep Unit 2 shutdown until allowed to restart by the NRC Region I Regional Administrator.
This commitment was documented in confirmatory action letter (CAL)91-012, dated August 13, 1991, and CAL 91-013, dated August 15, 1991.
Based on the findings of the IIT, NRC Region I developed a Unit 2 restart inspection plan and sent a restart readiness assessment team (RRAT) to the site on September 3, 1991.
The RRAT led by,a senior resident inspector, consisted of a resident inspector, and several regional and headquarters based inspectors.
This team completed their review of the restart readiness of, Unit 2 on September 16.
The findings of this inspection will be documented in Inspection Report 410/91-81. In conjunction with this review, NRR completed a root cause determination for th'e UPS failure and documented it in a September 15, 1991, safety evaluation report.
On September 16, the NRC presented the findings of the RRAT and NRR root cause determination to NMPC in a public exit meeting held in Lanigan Hall at SUNY-Oswego.
Following this meeting members of the public were invited to ask questions and make statements concerning the potential restart of Unit 2.
Following consideration of the inspection findings, the NRR root cause review'. and the comments received in the public meeting, the Region I Regional Administrator released NMPC from the CALs on September 18.
2.0 UNIT 2 RESTART ACTIVITIES (71707, 61726, 62703)
2.1 Plant Startu bservations The inspectors observed operations activities related to unit restart and found that the operators generally performed well. The inspection coverage included observation of routine activities in the control room, observation of surveillance testing on the RCIC system, and observation of shift briefings.
Routine activities observed in the control room were determined to be conducted well. Activities observed included withdrawal of control rods, establishment of feed pump operation, and control of routine work. The communications between operators and the senior operator were very good.
However, there were two instances where senior operators did not log conditions, as observed after the B feed pump would not start, which was determined to be caused by a closed suction pressure transmitter root valve, and after I&C determined that corrective maintenance was necessary on the RCIC governor to correct an oil leak.
In both cases no log entries were made.
This was discussed with the operations superintendent, who stated that he had made similar observations and that action was being taken to correct this issu Operators performing the RCIC'urveillance testing documented below in section 2.2 were observed to be very well prepared and able to conduct the testing with minimal problems.
However, there was one instance when the control room operator started the system without having the support desired by the system engineer and I&C personnel, to allow collection of startup transient data.
This was considered a minor test coordination concern that had no plant safety impact.
Numerous shift briefings were observed and found to be well conducted.
Each station shift supervisor (SSS) who briefed the operating crew was knowledgeable of the activities which needed to be conducted on the shift and adequately discussed the desired operations with the shift personnel.
The shift personn'el were attentive during the discussions and asked appropriate questions.-
2.2 Reac r
re I lation lin Surveillance and orrective Maintenance The I&Cdepartment conducted adequate RCIC control system tuning prior to unit restart.
This tuning was required following the oscillatory response of the system during the August 13, 1991, reactor scram, which required that the system be taken out of automatic flow control and placed in manual speed control.
This was reviewed and documented by the RRAT.
The inspector reviewed the completed work packages on the RCIC system and reviewed the post maintenance testing (PMT) required and found it generally acceptable.
However, the inspector noted several instances where the completed work packages, brought to the SSS for PMT and closeout, did not contain all of the procedures which were conducted.
Specifically, WR 189944, RCIC turbine speed hunting.
As part of the corrective maintenance, I&C performed portions ofinstrument maintenance procedure (IMP) ICS-010, RCIC Tuneup, which allowed recalibration of the governor and controller electronics.
Inspector review of the final work package in the control room indicated that the copy of IMP ICS-010 in the package was not for credit.
The reason the procedure was not credited was that it needed to be rewritten after it was performed because it did not follow generic GE guidance for RCIC tuneup operations.
This was recognized by NMPC before the procedure was used and I&C'technicians were told not to change any settings, based on the performance of the procedure.
The procedure was subsequently rewritten and performed satisfactorily.
However, there was no note of this on the work request, nor was the completed retest in the completed work packag WR 190991, RCIC turbine governor EGM replacement.
This work request stated that the EGM would be changed out in accordance with IMP.-ICS-0101. The work package contained the portion of the IMP performed to install the new EGM, however, the next-section of the procedure, to calibrate the new EGM was not in the work package.
The inspector identified this to the system engineer and I&Cpersonnel who quickly produced the completed procedure.
Although minor in significance, these examples of incomplete work package documentation indicated that the completed work request review process by I&C and quality control had not picked up these missing work documents.
Prior to unit restart NMPC decided to perform RCIC system flow and pressure testing at 150 psig, 500 psig, and 935 psig reactor pressure.
The inspector observed numerous RCIC system surveillance tests during the startup period; each test was very well conducted by the control room operators.
Further, the inspector found the test procedure adequately placed the system in conditions which should have caused oscillatory responses if the control system was not behaving properly.
RCIC system fiow oscillations did not occur during the first test at 150 psig reactor pressure.
However, at 500 and 935 psig reactor pressure, oscillatory responses occurred when step
. changes were made in the automatic flow control mode.
The reason why oscillations were not observed at 150 psig was'apparently due to the dampening effect of low steam pressure.
When the oscillatory responses were observed, the NMPC RCIC system engineer and I&C personnel took good action to correct the problems.
This eventually led to the replacement of the governor control system.
Final system testing following control system tuning was observed to be satisfactory.
3.0 PLANT OPERATIONS (71707, 71710)
3.1 Routine Plant eration Review -
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Based upon routine observations of control room activities during the inspection period, the inspectors determined that operator shift turnovers, shift crew briefings, panel manipulations and alarm response, and routine safety system and auxiliary system operations were conducted in accordance with approved operating procedures and administrative guidelines.
The inspectors independently verified safety system operability by review of operator logs, system markups, control panel walkdowns, and component status verifications in the field.
Operators and technicians in the field were familiar with current system status, and personnel responded well to events during the inspection perio.1.1 Emer enc olin tern Is lati n On September 9, the unit experienced an inadvertent isolation of the No. 12 emergency cooling loop. NMPC determined that the isolation occurred during the performance of surveillance N1-ISP-036-005, Lo-Lo-Lo Reactor Level Instrument Trip Channel Test/Calibration.
Instrument and control technicians had placed the selector switch on the RPS calibration unit to position 5, Emergency Condenser High Flow, rather than position 4, Lo-Lo-Lo Reactor Level.
This resulted in the inadvertent isolation of the No. 12 emergency cooling loop.
The proper NRC notifications were made under 10 CFR 50.73(9)(2)(iv).
The NMPC followup review of this event determined that the selector switch knob on the calibration unit.was reported by the technician to be loose, which contributed to the mispositioning of the knob. The allen screw securing the knob to the switch shaft was tightened.
Other corrective actions were to issue procedure changes to the surveillance procedures to check that the knobs are tight, conduct an accountability meeting, and issue a lessons learned transmittal to advise personnel of the event and what actions they should take to minimize the potential for similar occurrences.
The inspector reviewed the associated licensee event report, 91-10, and found it acceptable.
The emergency cooling loop was isolated for approximately four minutes when operations personnel promptly restored the system to normal.
The safety significance of this event was minimal because, while the No.
12 emergency cooling loop was isolated, the No.
11 loop remained operable to remove the decay heat energy generated.
The inspector's assessment of the causes of this event was that, although the knob was loose, increased diligence by the ISAAC technician could have prevented this event.
The technician did notice the knob was loose but felt this would not affect the performance of the test.
With the exception of this technician performance deficiency, no other concerns were identified.
3.1.2 Automatic Reactor cram F 11 win a
enerat r ad Re'ect On September 26, with reactor power at 97.8% power, an automatic reactor scram occurred due to a main generator load reject.
All systems performed as designed including the actuation of high pressure coolant injection to maintain reactor water level and all six electromatic relief valves opened for a short duration to control reactor pressure.
Operator response to the plant transient was prope Niagara Mohawk investigation determined a fault on the phase two neutral phase current transformer (CT) caused the 345 KV bus-to-neutral differential relay'o trip resulting in the generator load reject.
The reactor was placed in a cold shutdown condition to evaluate and correct the failur'e of the non-safety related CT. NMPC replaced the three neutral phase CTs with new ones.
The root cause of the CT failure was under investigation at the end of this inspection period. The root cause and corrective actions willbe reviewed upon issuance of'LER 91-12, The inspector determined the safety significance of this event was minimal because all systems functioned properly.
3.1.3 afet S stem Verification t
The inspector directly examined accessible portions ofemergency diesel generators (EDGs) ¹102 and ¹103 and their associated auxiliary systems, that included the starting air, cooling water, fuel oil handling and storage systems.
The inspector verified the EDGs and associated auxiliary systems were properly aligned in the standby mode.
As-built conditions matched the system P&ID with one exception, and the valves and switches were in the position indicated by the most recent valve and electrical lineup sheets and as required by system operating procedures.
The P&IDindicated that valve 96-111 DGA-5 (EDG
¹103 compressor 96-29 discharge)
was a globe valve, however, the valve was actually a ball valve.
NMPC issued a deviation/event report (DER) to address and correct the discrepancy.
The inspector found that valve 96-112 DGA-7 (EDG ¹103.compressor 96-30 discharge)
was missing on'e of four body bolts.
NMPC issued a work request to correct the discrepancy.
Further, the inspector noted that rust was present on the EDG cooling water pump ¹103 discharge piping in the screen house.
NMPC issued a housekeeping request to evaluate and correct the problem.
In summary, the EDGs and associated auxiliary systems standby mode lineups were found to be proper.
Several other minor issues were discussed and adequately resolved with the system engineer.
No safety significant issues or concerns were identified during the inspectio.2 Routine Plant rations Review - Unit 2 Based upon routine observations of control room activities during the inspection period, the inspectors determined operator shift turnovers, shift crew briefings, panel manipulations and alarm response, and routine safety system and auxiliary system operations were conducted in accordance with approved operating procedures and administrative guidelines.
The inspectors independently verified safety system operability by review of operator logs, system markups, control panel walkdowns and component status verifications in the field.
Operators and.
technicians in the field were familiar with current system status, and personnel responded well to operational problems and events during the inspection period.
3.2.1 afet stem Verificati n The inspectors directly examined accessible portions of the reactor core isolation cooling (RCIC)
system to verify that the system was properly aligned in the standby mode.
As-built conditions matched the system P&ID with one exception, and valves were in the positions indicated by the most recent valve lineup sheets and as required by system operating procedures.
The P&ID did not reflect a spare pressure instrument (PI-175) line downstream of valve *V234 (a drain line isolation valve at the discharge of the RCIC system pressure pump).
The instrument line, however, was identified on the system isometric drawing.
Niagara Mohawk has issued a deviation/event report (DER 2-91-Q-1153) to address and correct the-discrepancy.
Several other minor issues were discus'sed and adequately resolved with the system engineer.
No safety significant issues or concerns were identified.
4.0 RADIOLOGICALCONTROLS (71707)
4.1 R
i ine Radiol ical ontr l bservations -
nits 1 and 2 Routine walkdowns of the radiologically controlled areas of both units revealed good adherence to station standards.
However, the inspector noted that, following the venting of a RCIC flow transmitter at Unit 2, potentially contaminated water was left on the floor and in the instrument rack structure.
This was discussed with the radiation protection personnel on shift and with the Unit 2 radiation protection superintendent, and the area was cleaned up following the observatio.0 MAINTENANCE(62703)
5.1 Observati n of Maintenance Activities -
nit
The inspector observed the maintenance activities associated with work request 188637, Repair high vibration in the Number 11 control rod drive pump gearbox.
Mechanical maintenance technicians replaced gears in the gearbox to eliminate the excessive vibration. The technicians were observed to be experienced and used good procedural adherence.
Mechanical maintenance supervisory oversight was evident. The inspector reviewed the associated radiation work permit (RWP) 910351-01A and noted that instrument and control technicians working on the temperature switch were wearing cotton gloves when the RWP specified, rubber gloves.
A radiation protection technician at the job site changed the RWP to allow the use of cotton gloves.
The pump was run for a post maintenance test and vibration levels were satisfactory.
The inspector determin'ed that the maintenance activities were conducted properly.
6.0 SURVEILLANCE (61726)
6.1 Observation f Surveillance Activitie -
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6.1.1 ore ra Pum and Valve ua erl Te tin The surveillance test on the 112 core spray loop was observed to be properly run by the operations department, however, an unauthorized temporary modification was identified by the inspector concerning the 112 core spray pump motor cooler pressure control valve (PCV) 81-54.
On September 25, 1991, the inspector observed the performance of surveillance Nl-ST-Q1A Rev. 00, Core Spray Pump and Valve Operability Test, for core spray loop 112 per section 8.4.
The inspector noticed a test gage installed to PCV 81-54 was used to obtain setpoint data when the core spray pump was running per the surveillance test.
However, the test gage was not installed, removed, or controlled by the surveillance procedure.
The inspector reviewed the work package that was used to install the test gage to PCV 81-54.
Work Request 188215 was used to process the work and no work instructions other than skills of the trade per Attachment "A"of SMI-5.3-.001 were used to perform the work. The inspector identified three concerns with the way the test gage was installed.
The installation of the test gage per WR 188215 was not controlled or evaluated as part of surveillance Nl-ST-QIA Rev.
and thus was an unauthorized temporary modification. The inspector was particularly concerned because ofpreviously described problems concerning unauthorized temporary modifications identified by the NR When the plug in the bottom of PCV 81-54 was removed for a short period of time to install the test gage, this breached the pressure boundary of the core spray system and the system was not taken out of service, nor was an evaluation performed prior to the work to ensure that the core spray pump could still perform its safety function without overheating ifrequired to operate while the core spray motor cooler line was breached.
3.
No markup (isolation) was used when the gage was installed at PCV 81-54. The inspector was concerned about the personal safety aspect ofperforming the work without any isolation. Ifa core spray actuation occurred, potentially contaminated pressurized water from the core spray system would have sprayed out and been a potential hazard.
These concerns were discussed with the operations department supervisor who initiated three deviation/event reports to document and investigate the performance and safety issues.
The test gage was removed from PCV 81-54, as well as similar gages from other valves, and the system was restored to its normal configuration by the next day after performing this test.
The inspector noted that during pre-work package review, quality assurance personnel had two opportunities to identify these concerns and did not.
Further, there was no quality inspection coverage during the maintenance or testing. At the end of the inspection, the NMPC evaluation was still in progress.
This is an unresolved item (50-220/91-20-01)
pending review of the ongoing evaluation and corrective actions taken by NMPC.
7.0 SECURITY AND SAFEGUARDS (71707)
7.1 Routine Securit bserv i ns -
nit 1 and 2 Through routine observations of security activities the inspector determined that personnel and
. vehicle searches were properly conducted.
However, during a weekend inspection of the unit, an inspector identified a security guard seated at the bottom of a stair tower. The individual was observed to be seated under the stairs with a garbage can partially obscuring him.
When confronted by the inspector, the guard left the area before either his identity or duties could be determined.
At that time, the inspector verified that there was no apparent reason for posting a guard at that location.
This observation was discussed with security department supervision, who stated that their expectation for a guard, either on or offduty, was that they not be seated in obscure areas unless specifically required by their assigned duties.
This issue was discussed with plant management, who stated that actions would be taken to prevent such occurrences in the future.
Further, the security department was investigating this specific instance, and the findings of that investigation would be available for subsequent NRC inspector revie.0 ENGINEERING AND TECHNICALSUPPORT (92701)
8.1 Routine Review -
nit 1 8,1.1 Closed Violation 0-22 / 1-2- 2.
ontainment ra A
ndix J Water Seal Is ue Inspection reports gR) 50-220/90-09 and 91-02 discussed NRC identified deficiencies in NMPC's implementation of a water seal methodology on certain containment spray valves to satisfy 10 CFR 50, Appendix J leak testing requirements.
The unresolved items opened for this issue in IR 90-09 considered to constitute a violation in IR 91-02.
Comprehensive short-and long-term corrective actions for the violation were addressed in a NMPC letter dated April 12, 1991.
On June 13, 1991, a meeting was held at NRC headquarters at which NMPC discussed its corrective actions for the violation as well as their revised methodology for satisfying Appendix J leak test requirements.
Following that meeting, the NRC staff assessed that the actions taken and planned by NMPC to address the concerns were appropriate and technically sound.
Based on that review, the Appendix J water seal issue is considered to be resolved.
8.1.2 lo ed nre lved Item-22
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1-7 This item involved concerns over the method of controlling verbal exchange and approval of test data by telephone.
NMPC is considering two long-term options to address the concern; either allow review and approval of test data by telephone with requirements and controls for doing so specified in a procedure, or not allow telephone approval of data at all.
NMPC corporate engineering has committed to choose one of the options. by December 1991.
In the interim, review and approval of test data by telephone is not allowed.
This item is closed.
9.0 SAFETY ASSESSMENT AND QUALITYVERIFICATION 9.1.
Routine Review - Unit
9.1.1 Review of Licensee Event Re rts ERs and S ecial Re orts The following LERs were reviewed by the inspector and found satisfactory:
91-08, Reactor scram due to neutron monitoring trip while performing a controlled shutdown.
The events described in this LER were discussed in IR 50-220/91-12.
Due to the extremely short duration of the neutron monitoring spike, the root cause for this event could not be determined.
The most probable root cause was due to a small pressure spike when a main steam line drain valve was shut or due to neutron monitoring spiking caused by external electrical activity or electromagnetic interference.
The inspector reviewed the corrective actions taken and found them to be acceptable.
No concerns were identified during the review of this LE LER 91-10, Inadvertent isolation of number 11 emergency cooling loop.
This was discussed in Section 3.1.1 of this report.
9.1.2 Review of ite rations Review ommittee Meetin On September 24, 1991, the inspector attended a Unit 1 site operations review committee (SORC) meeting.
The inspector verified that the proper SORC quorum was satisfied and the designated Technical Specification oversight/review functions were adequately addressed.
The inspector observed generally good discussion and emphasis upon safe plant operations and operations support activities, although the Emergency Plan annual technical'review discussion was outside the purview of the SORC and could have been more appropriately addressed in a different forum.
The inspector concluded that the discussions observed were thorough and effective in addressing the safety significant issues and concerns.
9.2 Routine Review -
nit 2 9.2.2 The follow'ing LERs were reviewed by the inspector and found satisfactory:
91-14; Reactor building isolation and standby gas treatment syste m initiation due to personnel error.
The root cause was identified to be personnel error by site electricians during a troubleshooting activity. Specifically, they failed to verify the boundaries of the equipment markup and failed to notify the SSS that they were performing work outside their troubleshooting work plan.
The work outside of the boundary an'd work plan resulted in the deenergization of an electrical panel which initiated a false "damper closed" position to the RBVS exhaust fans which in turn tripped causing a low flow condition and subsequent initiation of the SGTS.
This issue was identified by NMPC, was oflow safety significance, and appropriate corrective actions were taken as described in the LER.
This licensee-identified violation of facility troubleshooting procedures is not being cited, since the criteria specified in section V.G of the Enforcement Policy were satisfied.
(410/91-20-02)
91-16, Supplement 1, TS violation caused by a mispositioned valve due to procedural inadequacy.
The events in this LER have been reviewed in inspection reports 91-12 and 91-17 and two apparent violations were identified.
Further, the event root cause identified in this LER was assessed as not fully adequate in IR 91-17.
The remainder of the LER was assessed to be adequat '
91-17, Transformer fault causes reactor scram and uninterruptible power*supply failure
'auses loss of annunciation which led to declaration of. a site area emergency (SAE).
This LER-documents the events surrounding the August 13 SAE.'he events described in this LER have been reviewed, documented and assessed in the NRC Incident Investigation Team and Restart Readiness Team Inspection reports.
88-59, Supplement 1, The supplement to this LER delineates further corrective actions taken by NMPC in response to the event.
The actions taken were assessed to be appropriate.
No further recurrences of the same event have taken place.
, 91-11, Technical Specification violation, missed chemistry surveillance due to personnel error.
The LER described the NMPC discovery, that the reactor water gross beta and gamma activity measurements had not been performed within the required 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; instead, following that discovery, the measurement was completed about 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> late.
The inspector reviewed this event and the corrective actions taken and determined that the event was of low safety significance; the failure to obtain the chemistry sample was an isolated event and was due solely to personnel error, not the result of a problem in the tracking method for TS required chemistry sampling; the corrective actions, in the form of a review of the tracking system, briefing chemistry personnel on the event, and issuance of a lessons learned transmittal appeared adequate.
This issue was identified by NMPC, was of low safety significance, and appropriate corrective actions were taken as described in the LER.
This licensee-identified violation of chemistry surveillance procedures is not being cited, since the criteria specified in section V.G of the Enforcement Policy were satisfied.
(410/91-20-03)
91-07, Two ESF actuations due to spurious low air flow signals.
The LER describes two separate initiations of the standby gas treatment system and secondary containment isolations.
The root cause of the event was determined to be spurious low air flow signals.
Immediate corrective actions were assessed to be adequate.
The inspector notes that longer term engineering analysis and review of these and previous spurious actuations is ongoing.
9.3 Review f erational Events A sessment Pr ram -
nits 1 and 2 The inspector reviewed and discussed the operational event assessment program and found that it was adequately tracking industry information. This program was recently taken over by the QA organization.
Each unit has an OEA supervisor who reports directly to the respective unit QA superintendent.
Issues reviewed by these groups include: NRC information notices, vendor information, and industry group. issues.-
Issues are received by these groups and are reviewed for applicability to either unit. Ifthe issue is deemed applicable to one, or both, units a DER is written for the unit(s) to direct site personnel review of the specific issues.
The DER is then returned to the OEA group for review of the disposition and closure of the issue.
The inspector found this system appropriate for the review of these issue '
The inspector discussed, specifically, the backlog of items that either have not been passed on to the site organizations for review or that have been passed on but not responded to yet by the site organizations.
The inspector found that this information was easily available from the monthly status update provided for the OEA supervisor to the QA superintendent.
At Unit 2 there were approximately 150 open issues out to the site for resolution and approximately sixty which needed OEA review before being sent to the site personnel.
The numbers of both categories of these issues has tended down since the OEA group was formed.
NMPC planned to have the current sixty Unit 2 OEA review issues reduced to zero by the end of the year.
10.0, MANAGEMENTMEETINGS At periodic intervals and at the conclusion of the inspection, meetings were held with senior station management to"discuss the scope and findings of this inspection.
Based on the NRC Region I review of this report and discussions held with Niagara Mohawk representatives, it was determined that this report does not contain safeguards or proprietary information..