IR 05000220/1988003
| ML17055D809 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 04/22/1988 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17055D808 | List: |
| References | |
| 50-220-88-03, 50-220-88-3, 50-410-88-02, 50-410-88-2, IEB-87-002, IEB-87-2, IEIN-88-005, IEIN-88-5, NUDOCS 8805030322 | |
| Download: ML17055D809 (30) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
Docket No.
License No.
Licensee:
88-03/88-02 50-220/50-410 DPR-63/NPF-69 Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, New York 13212 Faci 1 ity:
Location:
Dates:
Inspectors:
Nine Mile Point, Units 1 and
Scriba, New York February 1,
1988 to March 31, 1988 W.A. Cook, Senior Resident Inspector A.G. Krasopoulos, Reactor Engineer R.A. Laura, Reactor Engineer
. G.W. Meyer, Project Engineer R.A. Plasse, Resident Inspector, Fitzpatrick W.L. Schmidt, Resident Inspector Approved by:
J.
. Johnson, Chief, Reactor Projects Section 2C, DRP
~(>~ t ss'ate INSPECTION SUMMARY activities including Unit 1 refueling outage activities and Unit 2 power ascension testing, licensee 'action on previously identified items, plant tour s, surveillance testing review, maintenance review, safety system walkdowns, physical security review, LER review, IE Bulletin and Notice review, and review of emergency batteries.
This inspection involved 299 hours0.00346 days <br />0.0831 hours <br />4.943783e-4 weeks <br />1.137695e-4 months <br /> by the inspectors which included 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> of backshift inspection coverage and 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> of weekend inspection coverage.
Backshift inspections were conducted on 2/8-2/12, 2/15-2/19, 2/22-2/26, 3/2, 3/14-3/18, 3/28-4/1, and 4/4-4/8.
Weekend inspections were conducted on 2/13, 2/27, 2/28, 3/5, 3/6, 3/13 and 3/27.
Results:
Operations related events at both units (section 1. 1.a and 1.2.a)
indicate operator inattention to detail.
Two licensee identified violations regarding main steam line radiation monitor setpoints and weekly surveillance testing of EFPDs of operation at Unit 2 are discussed in section 1.2.b.
A cont;em for Unit 1 housekeeping is discussed in section 3. 1.
8805030322 880426 PDR ADOCK 05000220
DETAILS 1.
1.1 Review of Plant Events (71707, 93702, 40700, 86700)
UNIT
During this inspection period, the unit remained shutdown for the 1988 refueling outage.
The inspectors observed various refueling activities on the reactor building refuel floor including portions of the vessel floodup between February 13 and 16, fuel offloading between February
and 26, Inservice Inspection examinations and LPRM replacement activities.
No significant discrepancies were noted with any of those activities.
On February 25, Instrumentation and Control ( 18C) technicians were conducting calibrations of reactor vessel level instruments when an unanticipated emergency cooling system initiation signa'1 occurred.
The 18C technicians had completed the calibration on the reactor protection system (RPS)
Channel 11 instruments and were conducting the calibration of the RPS Channel 12 instruments when the one-of-two taken twice logic was satisfied to provide the system initiation signals The inspector determined that the RPS Channel 11 initiation signals were not reset prior to proceeding to the calibration of the Channel 12 instruments.
The apparent causes for this oversight were a calibration procedure deficiency and the inattention of the control room operators to ensure proper resetting of the RPS Channel 11 initiation signals prior to permitting work on the Channel 12 instruments.
The inspector verified a calibration procedure change was initiated and that station management addressed the operator inattention concern.
(Also see LER No. 88-04).
b.
On March 25, the licensee identified that based upon a review of all completed Type B and Type C local leak rate tests, to date, the as-found leakage total exceeds the
.60 La acceptance criteria.
As of March 25, the licensee had completed approximately 85% of the required Type B and C
leakage testing and the cumulative "as-found" leak rate was approximately 16,000 SCFD.
The value was considerably greater than the 9230 SCFD (.60 La) allowed.
The inspector determined that the licensee was performing corrective maintenance and leak rate retesting, as required, to ensure the "as-left" leak rate values were acceptable.
The inspectors will review the final cumulative local leak rate results and the integrated leak rate testing results prior to unit restart.
C.
On March 26, the licensee identified, during a pre-installation walkdown for a modification, that six fire barrier penetrations (three in Battery Board Room 23) were improperly designed and installed.
The penetrations were non-functional with concrete on one side and flamastic material on the other side of a wood plug.
The licensee was not able to immediately
determine how long these penetrations had n'ot met the 3-hour fire barrier rating.
Fire watch patrols were immediately initiated for compensatory action until the penetrations could be properly sealed.
1.2 UNIT 2 At the beginning of this inspection period, the unit was being restarted following the January 20, 1988 reactor scram.
Operator inspection of the drywell on February 4 during vessel heatup identified AOV-108 packing leakage.
The unit heatup was delayed until this problem was resolved.
Reactor power was eventually increased and Power Ascension Testing, TC-6, was started on February 11.
A planned reactor scram due to main steam isolation valve (MSIV) closure testing was conducted on February 15.
A reactor restart was commenced on February 18 and the unit achieved 100%
rated power operation for the first time on February 25 '
a.
On March 3, a planned generator full load reject test resulting in a reactor scram was conducted.
An unanticipated plant response to the load reject initiation signal caused a low reactor vessel with RCIC and HPCS automatic initiations.
An Unusual Event was declared and then downgraded after reactor vessel level was restored.
Inspection observations of this test were documented in Inspection Report 50-220/88-07 and 50-410/88-06.
Modifications to the offsite power distribution protective relay circuit were made prior to unit restart on March 10.
On March 11, the licensee commenced Commercial Operation of Unit 2.
On March 13, a reactor scram occur red from full power due to the gross failure of a steam dome pressure transmitter.
An Unusual Event was declared for this event because of RCIC and HPCS automatic actuations to maintain reactor vessel level.
A reactor startup was commenced on March
'7, but delayed due to air entrapment in the control rod drive (CRD)
system'due to a stuck open relief valve on a
CRD pump suction line.
A reactor scram occurred on March 21 due to operator error (inspector review of this event is documented below).
Reactor restart was conducted on March 25 and the unit remained at power through the end of the inspection period.
Based upon followup of the events highlighted above, the inspectors concluded the following:
Evidence of thorough li'censed operator drywell inspections was noted by the.February 4 identification of AOV-108 packing leakage and the February 19 identification of a stuck open safety relief valve vacuum breaker.
The inspector verified that licensee actions to correct the packing leakage and to retest AOV-108 prior to returning it to service were appropriat The March 21 reactor scram was caused by control room inattention to detail in reviewing a feedwater flow transmitter calibration procedure.
The operators did not thoroughly assess plant impact when the transmitter was isolated per procedure.
The false transmitter output signal caused a reactor vessel level transient resulting in the reactor scram.
The calibration procedure did have an accurate plant impact statement, but lacked clarity.
Further details of this event are documented in LER No. 88-17.
Inspector review of the licensee's post-trip review summaries of the February 15, March 3, March 13, and March 21 reactor scrams concluded that the licensee reviews were thorough and accurate.
Systems problems and/or operating concerns were appropriately resolved prior to reactor restart.
The unanticipated plant response to the March 5 generator load reject test indicated that the licensee did not fully understand the Scriba Substation protective tripping relay circuitry.
The inspector verified that the licensee adequately modified and tested the trip relay circuit prior to unit restart.
No deficiencies were noted.
b.
The following events also occurred during this inspection period and inspector observations are highlighted:
On February 16, an inadvertant MSIV isolation occurred while the licensee was conducting stroke time testing of the turbine stop
'alves.
Unanticipated MSIV isolations due to operator lack of familiarity with the isolation logic or inattention to detail have been a recur ring problem at Unit 2 during the past year.
Although not a significant safety concern, in and of itself, licensee corrective actions for this work control and operator attentiveness concern have not been fully effective.
On February 19, the licensee determined that the main steam line radiation monitors'larm and trip setpoints were initially set less conservatively than'equired by Technical Specifications (TS).
The 3 times Full Power Background alarm and trip setpoints were initially set at 1500 mr/hr and 2500 mr/hr, respectively, based upon other newly operated boiling water reactor average full power steam line radiation levels.
Recently established normal full power radiation levels were found by the licensee to be lower than expected.
The new alarm and trip setpoint values are 1000 mr/hr and 1375 mr/hr, respectively.
In accordance with the provisions of the Enforcement Policy guidance of 10 CFR 2, Appendix C, no Notice of Violation is being issued for this TS 3.3. 1 and 3.3.2 violation.
The licensee identified and promptly reported this TS violation to the NRC.
There were no
'imilar TS violations for which corrective actions could have
reasonable been expected to have prevented this violation.
Licensee corrective actions to recalibrate the radiation monitor alarm and trip setpoints were prompt and adequate.
NO VIOLATION ISSUED (50-410/88-02-01).
On February 24, the licensee identified that they had missed a
TS special test exception surveillance requirement to calculate the effective full-power days (EFPD) of operation every seven days, to ensure that 120 EFPD is not exceeded during the Power Ascension Testing Program and prior to containment inerting.
The inspector determined that the cause for this missed surveillance was personnel error.
The calculation for this surveillance had not been specifically completed since February 5; however, the reactor analysts on shift calculate the effective full power hours of operation daily to monitor fuel burnup.
At the time, this surveillance was missed, the total EFPD was less than 40 and the unit was approximately one month from completion of the Power Ascension Testing Program.
The inspector discussed the circumstances leading to the oversight in performance of this surveillance test with licensee management.
Corrective action to prevent recurrence included:
lessening the workload of the individual responsible for the surveillance; reassignment of the surveillance scheduling to the Planning Department (who generate the master surveillance test schedule);
and making provisions for more independent checks of completion of the surveillance by the reactor analyst on duty.
There have been no similar Special Test Exception Surveillance Testing oversights by the licensee and this TS violation wa's identified and promptly reported to the NRC by the licensee.
In accordance with the provisions of the Enforcement Policy guidance of 10 CFR 2, Appendix C,
no Notice of Violation is being issued for this TS 4. 10.5 violation ~
NO VIOLATION ISSUED (50-410/88-02-02).
The inspectors verified that the licensee made the appropriate
CFR 50.72 notifications via the Emergency Notification System for all of the Unit 1 and Unit 2 events discussed above.
2.
Followu on Previous Identified Items (92702, 92700, 94702, 71707)
2.1 Unit
'a
~
(Open)
UNRESOLVED ITEM (50-220/87-24-02):
Potential noncompliance with June 1983 Confirmatory Order concerning SDV design.
On March 1, 1988, a
meeting was held in NRC Headquarters to discuss the scram discharge volume design.
The licensee had filmed an internal examination of the instrument headers that showed no corrosion buildup or restriction.
This film was presented to the NRC staff for review during the meeting.
The
licensee was asked to perform a scram test during startup following the 1988 refuel outage as described in the Confirmatory Order dated June 24, 1983.
Further NRC staff review of this item is pending.
This item remains open.
(Closed)
UNRESOLVED ITEM (50-220/87-10-02):
This item was left unresolved pending further review by the licensee to determine whether adequate troubleshooting and root cause determination were performed following the failure of the ¹11 liquid poison pump breaker (GE-AK-2A-25).
The inspector determined that the licensee conducted a thorough review of preventive and corrective maintenance performed on the ¹11 liquid poison pump breaker and concluded that adequate troubleshooting was not performed.
Maintenance Department management concluded that insufficient time was devoted to the initial breaker troubleshooting effort and that the electricians and first-line supervisors were inadequately trained to conduct thorough root cause determinations.
The inspector determined that changes in staffing and work prioritization have been made to address these concerns, along with additional training in troubleshooting and root cause analysis skills.
This item is resolved.
C.
(Open)
UNRESOLVED ITEM (50-220/87-21-06):
This item was made unresolved pending NRC review of licensee Engineering staff disposition of outstanding Inservice Inspection (ISI) DCAs.
Specialist inspectors have conducted some followup of this item as documented in Inspection Report 50-220/88-09 and 50-220/88-09.
In response to this item and other related ISI Program violations, the licensee has initiated a reorganization and revision of the implementing procedures for the ISI Program.
The inspector discussed these pending changes with licensee guality Assurance Department representatives on March 22.
A transition organization has been appointed, in the interim, to ensure proper implementation of the ISI Program during the Unit
refueling outage and to provide closer Engineering staff oversight.
The transition team has also been tasked with development of the implementing procedures which will become the responsibility of the gA Department after the transition is completed.
The licensee is targeting completion of this transition to the beginning of the Unit 2 May 1988 planned outage.
Further inspector review of this item and licensee corrective actions will be conducted in a subsequent inspection.
2.2 Unit 2 a.
(Closed)
INSPECTOR FOLLOWUP (No Number Assigned)
The inspector determined that the licensee has incorporated graphic overlays at the containment leak rate monitoring panel to allow quantification of leak rates based on drywell equipment and floor drain sump level strip chart indications.
This was identified earlier as a potential problem because there was no proceduralized way to determine leak rates if the electronic leak rate instrumentation was not operable.
This item is close (Closed)
VIOLATION (50-410/86-37-01):
Failure to follow the procedure.
specifying the environmental qualification (EQ) requirements for Rosemount transmitters.
During an earlier inspection of the instrumentation and cabling installations, the inspector observed that some Rosemount transmitters had joose covers.
The licensee's procedures required that the covers be torque tightened to ensure proper environmental seal.
The inspector also raised a concern that the governing procedures were not specific enough in that the procedure did not identify the torque requirements, replacement criteria of the 0-rings or the proper use of silicon grease.
The inspector determined that the licensee has revised procedure N2-IMP-EQM-005, Environmental Qualification requirements for replacement of Rosemount 1153 Transmitters.
In the revision of this procedure, the licensee has identified the specific EQ requirements for each transmitter environmental seal or pressure/mechanical boundary, in addition to providing more specific instructions for maintenance and transmitter replacement.
The licensee also revised N2-IMP-GEN-002, the procedure for repair of Rosemount Model 1153 Series'
transmitters.
Ispector review of these procedures and observations of installed transmitters did not identify any unacceptable conditions. 'he actions taken by the licensee to correct this violation were satisfactory.
This violation is closed.
(Closed)
UNRESOLVED ITEM (50-410/87-45-05):
This item was left unresolved pending licensee resolution of a determination that the suppression chamber maximum ambient air temperature limit of 90 degrees F was too restrictive.
The inspector reviewed the design evaluations associated with the increase of the wetwell air temperature alarm setpoint from 90 degrees F to 110 degrees F.
This increase was necessitated by the operational and design issues raised by the temperature frequently approaching and sometimes exceeding the 90 degree alarm setpoint, which was also assumed in the design analyses of the containment.
When the reactor is operating, the elevated drywell temperatures result in heat being transmitted to the wetwell air space (directly below the drywell)
via the relief valve downcomers and the diaphragm between the two air spaces.
This necessitated that the residual heat removal (RHR) system be utilized in the containment cooling mode to reduce the wetwell air temperature as often as once per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> shift.
On ocassion, the wetwell temperature exceeded the alarm setpoint.
The inspector noted that there are no Technical Specification (TS) requirements on wetwell air space temperature and the TS requirements on wetwell water temperature were not exceeded.
The inspector reviewed Safety Evaluation No.88-005 dated January 18, 1988, for the 20 degree temperature increase.
The evaluation concluded that the increase was acceptable and had an insignificant effect on the containment design, primarily due to the negligible heat capacity of the air space when compared to the water in the suppression pool.
The safety evaluation reviewed the temperature increase effect on accident analyses, equipment qualification, and the mechanical, electrical, and structural design of the effected components and found them to be acceptabl J
Based on the above, the inspector concluded that the setpoint increase was acceptable and that the infrequent occasions when the wetwell temperature had exceeded that design assumption of 90 degrees had no safety impact.
Based on discussions with a Station Shift Supervisor, the inspector concluded that the setpoint increase had a positive safety effect, in that RHR will need to be operated in the containment cooling mode approximately one-third as frequently, which will minimize potential degradation of the RHR System.
This item is resolved.
d
~
(Open)
UNRESOLVED ITEM (50-410/87-45-06):
Licensee resolution of material control concerns.
This item was identified during the previous inspection period to track licensee progress in resolving control of commercial grade items procured for application in safety-related systems.
On March 14, the licensee determined that seventeen high pressure core spray (HPCS)
system switchgear relays were not qualified for safety related application based upon inadequate documentation.
The HPCS system was immediately declared inoperable and the appropriate
CFR 50.72 notification was made.
The licensee is submitting a voluntary LER to provide further details on this event.
The inspector will review licensee resolution of this concern, in conjunction with the broader material control concerns, during a subsequent inspection.
This item remains open.
Plant Ins ection Tours (71707, 71710, 62703)
During this reporting period, the inspectors made tours of the Unit 1 and 2 control rooms and accessible plant areas to monitor station activities and to make an independent assessment of equipment status, radiological conditions, safety and adherence to regulatory requirements.
The following were observed:
3.1 Unit
During the previous inspection period, numerous examples of poor housekeeping and radiological controls practices were observed in the reactor building and discussed with station management for corrective action.
A visit by a region based inspector the week of February
(reference Inspection Report 50-220/88-04 and 50-410/88-05) identified many of the same poor housekeeping practices and uncorrected items.
Towards the end of this inspection period, Unit 1 housekeeping was significantly improved; however, station management has been slow in responding to this issue.
3.2 Unit 2 On March 30, 1988, the Regional Administrator toured the station and noted that during tours of the control room the operators were found to have a good knowledge of work activities ongoing in the field and of annunciators alarming on remote panels in the plan b.
C.
On March 3 during a reactor startup the inspector noted that the step in Startup Procedure OP-101A requiring high to low pressure interface valves to be deenergized, was not signed off while the reactor was in the RUN mode.
The inspector verified that the valves which were not in use at the time were in fact deenergized and tagged out.
The licensee has made a change to the procedure to ensure that this specific step is signed off prior to entering the RUN mode During tours of the emergency diesel generator (EDG) rooms, the inspector identified loose exhaust, manifold flange bolts on the EDG turbocharger.
The inspector notified the control room of this condition and a Work Request was issued to address this item.
Subsequent followup by the inspector determined that the Work Request was closed out; however, inspection of the diesel identified the bolts to still be loose.
An apparent misunderstanding of the problem resulted in different flange bolts being checked by the mechanical maintenance staff.
The inspector showed a licensed operator the specific bolts and subsequently verified that these bolts were properly torqued per a station Work Request.
The inspector also verified that the EDG preventive maintenance procedures
were revised to ensure periodic checks of the bolts.
d.
During tours of the Service Water Bays, the, inspector noted excessive rusting of the bolts on service water pumps.
The inspector discussed this problem with the mechanics who were working on the B service water pump.
The mechanics stated that the rusting caused problems when attempting to loosen or tighten the bolts.
The inspector discussed this problem with the Superintendent of Mechanical Maintenance who subsequently initiated a Problem Report for Engineering review and long term corrective action.
No violations were identified.
Surveillance Review (61726, 72302, 72301, 86700)
The inspector s observed portions of the surveillance test procedures listed below to verify that the test instrumentation was properly calibrated, approved procedures were used, the work was performed by qualified personnel, limiting conditions for operations were met, and the system was correctly restored following the testing.
Unit
The inspector observed various phases of the reactor core off-load during the week of February 22.
No discrepancies were noted.
During the week of March 21, a
NRC Team Inspection was conducted to review various outage surveillance testing, maintenance and modification activities.
The team's findings are documented in Inspection Report 50-220/88-07 and 50-410/88-0.2 Unit 2 N2-0SP-RMC-WQ001, Control Rod Movement and Position Indicator Verification, Revision 0, dated December 1986, performed on February 26.
N2-SUT-23-6, Section 6. 13, Feedwater Pump Trip, conducted on March 5.
N2-SUT-23-6, Loss of Feedwater Heating, conducted March 4.
N2-SUT-30.6, Recirculation Pump Trip, conducted March 1.
No discrepancies were noted.
(Inspector observations during the Generator Load Reject Test are discussed in section 1.2.a of this report).
5.
Maintenance Review (62703, 37700, 37701)
The inspector observed portions of various safety-related maintenance activities to determine that redundant components were operable, that, these activities did not violate the limiting conditions for operation, that required administrative approvals and tagouts were obtained prior to initiating the work, that approved procedures were used or that the activity was within the "skills of the trade", that appropriate radiological controls were implemented, that ignition/fire prevention controls were properly implemented, and that equipment was properly tested prior to returning it to service.
The following maintenance activities were observed:
5.1 Unit
a.
The inspector reviewed the maintenance conducted on the 1000 pound refuel floor hoist.
The licensee actions to return the hoist to service were found to be adequate.
b.
Nl-FHP-23, LPRM Removal and Installation, Revision 5, dated March 1986, observed the week of March 14.
c.
As stated in section 4. l.b of this report, the NRC Team Inspection findings pertaining to maintenance activities are documented in Inspection Report 50-220/88-07 and 50-410/88-06.
d.
N1-NMP-01-203, Removal, Overhaul and Replacement of Main Steam Electromatic Relief Valves and Associated Pilot Valves, observed during the week of March 28.
No violations were identifie.2 Unit 2 The inspector reviewed the repair of the High Pressure Core Spray testable check valve (AOV-108).
The valve had earlier been repacked, but failed to operate properly on the retest.
The Maintenance Department evaluated the problem as being caused by swelling of the grafoi 1 packing that was installed to replace the original graphite impregnated flax packing.
No discrepancies were noted.
Review of major maintenance conducted on the B service water pump demonstrated good coordination and oversight by first-line supervision.
No discrepancies were noted.
The inspector discussed known problems on Cooper Bessemer Model KSV diesel engines with personnel from NRC Headquarters.
At Unit 2, two sixteen cylinder Model KSV engines are used as prime movers for the Division I and II emergency generators.
Cooper Bessemer issues Service Newsletters (to companies who have purchased their machines)
which provide information on how to better operate and maintain the diesel engines.
The inspector asked the'icensee to provide copies of the Service Newsletters.
The licensee could not initially produce this correspondence and requested them from Cooper Bessemer.
6.
Following subsequent review of these Newsletters, the inspector determined that there have been no cases where failure to implement the recommendations (outlined in these Service Newsletters)
has adversely impacted the operability of either diesel engine.
The licensee has committed to review the past and future Service Newsletters and to assess the need for implementation of the recommendations.
This topic will be reviewed in a-subsequent inspection period to evaluate licensee actions.
No violations were indentified.
(Also, see comments in section 3.2.c and 3.2.d above.)
Safet S stem 0 erabilit Verification (71710)
On a sample basis, the inspectors directly examined selected safety system trains to verify that the systems were properly aligned in the standby mode.
The following systems were examined:
6.1 Unit
Core Spray Emergency Diesel Generators 6.2 Unit 2 HPCS Residual Heat Removal
Emergency Diesel Generators No violations were identified.
7.
Ph sical Securit Review (71709)
The inspector made observations to verify that selected aspects of the station physical security program were in accordance with regulatory requirements, physical security plan and approved procedures.
7. 1 Unit 1 and Unit 2 During this inspection period, the inspector reviewed recent Operations staff involvement with Security Department Site Contingency Drills.
Since June 1987, the licensee has involved the on-duty Operations shifts from both units in over 20 contingency drills.
The inspector also discussed a recent licensee initiative involving the development of a new draft Emergency Preparedness Procedure (EPP-10)
which addresses station secur ity threats.
No discrepancies were noted.
8.
Review of Licensee Event Re orts LERs (90712, 92700)
The LERs submitted to the NRC were reviewed to determine whether the details were clearly reported, the cause(s)
properly identified and the corrective actions appropriate.
The inspectors also determined whether the assessment of potential safety consequences'had been properly evaluated, whether generic implications were indicated, whether the event warranted on site follow-up, whether the reporting requirements of 10CFR50.72 were applicable, and whether the requirements of 10CFR50.73 had been properly met.
(Note: the dates indicated are the event dates)
8.1 Unit 2 The following LERs were reviewed and found to be satisfactory:
87-61, 10/1/87, Missed surveillance on primary containment airborne parti cul ate moni tor.
87-62, 10/27/87, LPCI not declared inoperable after a
surveillance test was failed.
87-65, 10/15/87, Secondary containment negative pressure not maintained due to a design deficiency.
87-66, 10/20/88, Mode 2 entered with one train of Standby Liquid Control system inoperable.
87-81, 12/26/87, Reactor scram due to loss of condenser vacuum.
87-82, 12/29/87, Hain steam isolation valve closure due to mispositioning of the reactor mode switc,
12/30/87, Gaseous effluent monitor inoperable 88-10, 2/24/88, Missed surveillance on effective full power days of operation.
No violations were identified.
Licensee Action on NRC Bulletins and Information Notices (92701, 92703)
The inspector reviewed licensee records relating to the NRC Bulletins and Notices identified below to verify that:
the NRC Bulletins and Notices were received and reviewed for applicability; written responses were provided, if required; and the corrective action taken was adequate.
9.1 NRC Notice 88-05: Fire in Annunciator Control Cabinets.
This NRC Notice was issued February 12, 1988 and alerted licensees of three recent occurrences of electrical fires in annunciator control 'panels supplied by Electro Devices, Inc.
The electrical fires occurred in remote cabinets containing multiple circuit cards for the control of visual and audible annunciator functions in the main control rooms.
9.2 The inspector discussed this Notice with licensee representatives and determined that the annunciator control cabinets at Units 1 and 2 were provided by Rochester Instrumentation Systems, Inc.
In addition, the inspector determined that the control cabinets installed at Unit 2 have been closely monitored for internal temperatures because of electrical loading.
At the time of the inspector's inquiry, the licensee had completed modifications to approximately 60% of the cabinets'ront panels to install additional louvers for better internal cooling.
No specific problems have been experienced with these annunciator panels;
~ however, the licensee has implemented a temporary temperature monitoring program to ensure no future cabinet overheating problems.
NRC Bulletin 87-02:
Fastener Testing to Determine Conformance with Applicable Material Specifications.
The purpose of this bulletin, dated November 6, 1987, was to request that licensee's review their receipt inspection requirements and internal controls for fasteners and independently determine whether fasteners in stores at their facilities meet required mechanical and chemical specifications.
The inspector participated in the licensee's fastener selection process and verified that the sampling of fasteners was representative of in-plant use.
Special interest fasteners were identified and included in the sample selection.
The inspector also verified that each fastener selected was appropriately tagged for identification and testing purposes.
The licensee selected fasteners from both Unit 1 and 2 warehouses, shipped these items to an independent laboratory for analysis and submitted separate responses with the analysis results for each uni Licensee-to-NRC letters NMP1L-0226 and NMP2L-1113, dated February 19, 1988, document their responses to this bulletin.
A preliminary review of the responses and test data indicate that appropriate licensee action was taken.
Detailed review of the fastener test results will be conducted in a subsequent inspection.
No problems were identified during this review.
10.
Batter Condition Followu (61726, 62703, 92701)
After NRC management review of the results'f an earlier inspection of storage battery adequacy (Inspection Report 50-220/87-25 and 50-410/87-45, section 15) additional followup was requested.
A concern was raised regarding the potential unreviewed installation of ignition sources (i'ortable heating units, light-switches, or other spark or high heat producing devices)
in battery rooms where hydrogen concentrations could potentially reach flammable limi'ts.
Inspector followup identified that battery room ventilation systems at both units are of sufficient capacity to ensure hydrogen concentrations are maintained below explosive limits.
In addition, the Unit 1 battery rooms are equipped with an alarm system to detect a loss of ventilation.
The Unit 2 battery rooms are equipped with two redundant safety-related, 1E-powered exhaust fans.
Upon loss of one fan, the other fan starts automatically on indication of loss of air flow.
The inspector reviewed the following:
NRC, Fire Protection Safety Evaluation Report, Nine Mile Point-Unit 1, dated July 26, 1979.
NUREG-1047, Safety Evaluation Report, Nine Mile Point Unit 2, dated February 15, 1985.
The inspector had no further questions and no conerns were identified.
11.
Review of RBCLC Heat Exchan er Sto Work Order (93702)
Between February 20 and 25, 1988, the Quality Assurance (QA) Department issued a Stop Work Order=op the reactor building closed loop cooling (RBCLC) heat exchanger replacement activities (modification No
~ 1016).
The Stop Work Order was issued due to numerous quality related deficiencies identified by the site QA organization while conducting surveillance activities of the contractor's work.
These deficiencies involved poor QA practices by the contractor including inadequate documentation, material traceability concerns and unsupported variances from Quality Control inspection attributes.
The inspector will be provided with a detailed summary of the licensee's findings and resolutions for review during the subsequent routine inspection perio.
Assurance of ualit Summar (30702, 30703)
The Emergency Cooling initiation at Unit 1, the Unit 2 main steam isolation valve automatic closure whi.,le shutdown and the March 21 reactor
, scram at Unit 2 are examples of operator inattention to detail.
Licensee identification of two.-TS violations at Unit 2 is commended; however, the missed EFPD surveillance test is indicative of an intermittent problem with proper implementation of the Unit 2 Surveillance Testing Program.
Management attention is warranted in this area to ensure each station department is properly tracking and implementing the program.
Operator findings during tours of the Unit-2 containment during unit startup are indicative of thorough system walkdowns.
Earlier in the inspection period licensee housekeeping efforts at Unit
were ineffective.
Towards the end of the inspection period these efforts were much improved.
Continued station employee and licensee management attention is needed to maintain this
'level of cleanliness and material condition.
QA department identification of quality assurance concerns during, routine surveillance of the RBCLC heat exchanger replacement activities is indicative of good QA/QC oversight, but poor licensee Engineering staff overview of the contractor's modification efforts during the planning and implementation phases.
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 licensee representatives, it was determined that this report does not contain Safeguards or 10 CFR 2.790 informatio ~