IR 05000220/1988020
| ML17055E492 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 01/25/1989 |
| From: | Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17055E491 | List: |
| References | |
| TASK-2.K.3.01, TASK-TM 50-220-88-20, 50-410-88-20, NUDOCS 8902070221 | |
| Download: ML17055E492 (40) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION I
Report No.
Docket No.
License No.
Licensee:
88-20/88-20 50-220/50-410 DPR-63/NPF-69 Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, New York 13212 Faci 1 i ty:
Location:
Nine Mile Point, Units 1 and
Scriba, New York Dates:
November 18, 1988 through January 6,
1989 Inspectors:
W.A. Cook, Senior Resident Inspector R.R.
Temps, Resident Inspector R;AD Laura, Resident Inspector R.S. Barkley, Reactor Engineer J.E.
Carrasco, Reactor Engineer, DRS Approved by:
. Joh on, Chief, Reactor Projects Section 2C, DRP l~les t~
Date INSPECTION SUMMARY Areas
~Ins ected:
Routine inspection by the resident inspectors of station activities including Unit 1 and 2 shutdown plant operations, licensee action on previously identified items, plant tours, safety system walkdowns, surveillance testing, reviews, maintenance reviews, and LER reviews.
This inspection involved 317 hours0.00367 days <br />0.0881 hours <br />5.241402e-4 weeks <br />1.206185e-4 months <br /> by the inspectors which included 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> of backshift inspection coverage.
, Results:
Concerns regarding three different personnel errors occurring during the work release process in Unit 2 are discussed in sections 1;2.b, 1.2.c and
'.2
'.
A Unit 1 licensee identified violation is discussed in section 1. l.b.
An unresolved item concerning the Unit
125 VDC system not meeting its design basis is discussed in Section l. l.c.
An unresolved item concerning vital equipment access control at Unit 1 is discussed in Section 7.e.
An unsatisfactory housekeeping issue was found in Unit 2's Service Water Bay by the inspector and is discussed in Section 3.2.a.
8902070221 890126 PDR ADOCK 05000220
PNU
DETAILS Review of Plant Events (71707,71710,93702,90712,71881,71709)
UNIT
The unit remains in Cold Shutdown with the core offloaded.
The NRC Restart Panel is currently scheduled to meet on-site to provide an assessment of the Restart Action Plan in late January.
The following events occurred during this time period:
On November 25 at approximately 7:00 pm, the licensee made a courtesy call to the senior resident inspector and the NRC headquarters duty officer informing them of an earthquake experienced in the'ortheast region.
The Federal Emergency Management Agency ( FEMA) subsequently notified the licensee that the earthquake epicenter was 90 miles north of quebec City, Canada, and had a magnitude of 6.2 on the Richter scale.
Unit 1 personnel did not feel the tremor in the control room; however, annunciator H2-1-6 (Seismic Detection Equipment Event) flashed on momentarily during the earthquake and then extinguished.
NMP Unit 2 and the Fitzpatrick power plants did not experience any alarms or unusual occurrences during the seismic event.
The Unit 1 operators checked the seismic equipment panel and initially noted no actuation of the seismic recorders or seismic event indication lights.
Initial verification of the seismic event was made via Niagara Mohawk employees off site calling into the control room to question operators of the possible effects on the plant of the tremors.
Subsequent investigation by the licensee, with the assistance of the seismic equipment vendor, determined that the seismic accelerometers and'ecorders were triggered by the event.
The white indicator light on the recorder was found to be lit indicati'ng a seismic event had occurred and that the monitoring equipment had functioned, as designed.
The licensee learned that the panel annunciator and recorder yellow indicating light only activate during the event.
The inspector and licensee determined that due to inadequate training the operators did not recognize that the seismic equipment had been triggered and had recorded the event.
The licensee conducted a preliminary analysis of the tapes from the four recorders and did not note any significant seismic activity.
The tapes were sent to the vendor for final analysis and their review confirmed the licensee's preliminary assessment.
The licensee has performed a
calibration of the seismic detectors and found them to be within the acceptable band.
Procedure Nl-OP-S3, Miscellaneous Annunciator Procedure For Correcting Alarm Conditions, was modified via a Temporary Change Notice (TCN) subsequent to this event to ensure the seismic recorder indicator light is checked to determine whether the equipment has been triggere Procedure Nl-OP-53 also references the Emergency Plan and Emergency Planning Administrative Procedures (EAP) -1 and EAP-2.
EAP-1 and EAP-2 address activation of the Emergency Plan and event classification, respectively.
During the subject seismic event, an Unusual Event was not declared.
EAP-2, Attachment 1, requires a'n Unusual Event be declared if there is any earthquake felt in the plant or detected on station seismic instrumentation by a valid alarm trip.
Unit 1 Operations management is reviewing this requirement and plans to issue guidance to the operators regarding how to classify and/or identify a valid seismic event.
The inspectors will review the licensee's actions in this regard in a
subsequent inspection period.
On December 22, the licensee found the door to the Flat Bed Filter Room in the radwaste building unlocked.
This door is required to be locked by Technical Specification 6. 12.2 due to the general area radiation levels being greater than 1000 mR/hr inside the room.
The cause of the unlocked door was determined by the licensee to be due to a failure of the locking mechanism to operate properly.
The licensee initiated a 50.73 notification to the NRC and also notified NRC Headquarters via a red phone call.
The immediate corrective action taken by the licensee was to lock the subject door using a chain and lock assembly until the locking mechanism in the door is rep'laced.
Subsequent review by the licensee identified seven other doors that use the same style lock assembly.
The licensee is employing temporary measures to ensure these additional doors remain locked, as required.
Long term corrective action will be to install a
"
different style lock assemby in these doors.
This event is considered a licensee identified violation.
In accordance with 10 CFR 2, Appendix C, no notice of violation is being issued.
(50-220'/88-20-03)
On November 18, Unit 1 informed the Headquarters Duty Officer via Emergency Notification System (ENS) that the 125 VDC system does not meet its design basis.
This determination was made following an Engineering staff review of design modifications to the system.
The inspector determined that the unit has two batteries associated with its 125 VDC system.
Each battery is supplied and charged via a battery charging motor generator (MG) set.
The battery charging NG set consists of a 600 VAC motor, a
120 VAC generator and a
125 VDC motor/generator.
Mith AC power available from its normal source (power board 16 or 17),
the 600 VAC motor provides rotational motion while the AC generator provides power to emergency lighting and the DC generator provides the 125 VDC power boards and maintains a floating charge on the batteries.
On a loss of 600 VAC, the DC generator becomes a
DC motor utilizing power from the battery to provide rotational force to the 120 VAC generator and emergency lighting.
Additionally, the batteries continue to supply other DC loads (ie. breaker control power, DC solenoids, etc.).
The design basis problem involves battery voltage potentially dropping significantly below the design 125 VDC.
Technical Specifications (TS)
estate that minimum voltage to consider a battery operable is 106 VDC.
However, licensee studies show that with less than 114 VDC present at the battery terminals, the actual voltage supplied at the different power boards will be approximately
VDC, due to resistive line losses.
The.
VDC may not be sufficient to allow breaker operation at the power boards.
The licensee considers this situation to be more severe in the event of a LOCA coincident with a loss of off-site power, as described in the FSAR.
On a loss of off-site power, the battery charging MG sets will lose their normal AC power source and will swap over to operation on the battery.
When the emergency diesel generators (EDGs) start to pick up AC loads, the battery chargers are supposed to automatically transfer back to their, normal AC source (power boards 16 and 17) after approximately two minutes.
However, if battery voltage is less than 114 VDC (well'bove the TS minimum operability limit) insufficient control power may exist for the battery chargers to swap back to their normal AC power source.
In this case, the MG sets continue to run off the batteries and the available DC voltage will continue to drop unless operator action is taken.
There is no indication in the control room to alert the operators to the fact that battery charger MG set swapover to the AC source has occurred.
As the battery voltage drops, the DC system voltage will drop low enough to cause EDG protective relays (which are DC powered and most of which deenergize to actuate)
to trip the EDGs.
This event would produce a
total loss of AC power thus exacerbating the LOCA.
This item remains
=open pending further evaluation and resolution by the licensee and subsequent inspector review.
UNRESOLVED (50-220/88-20-01)
This item was discussed with Unit 1 management at the inspectors'eekly meeting on November 23.
The inspectors expressed specific concern with the Engineering Department's ability to identify that the problem with the battery system, documented in the March 7, 1988,,"Nuclear Engineering Project Report for Battery Modifications", was reportable in accordance with NRC regulations.
Accordingly, this problem should have been passed up to higher management levels for reportabi lity consideration much sooner than it was.
Instead it took until November 1988 for the problem to be identified as reportable.
The reportability aspect was raised as a
result of an engineer in the station Technical Support group reviewing the project report and properly questioning the reportability.
This instance of failure of the Engineering staff to properly identify and report problems to management in a timely manner is not a singular event.
It has been and continues to be an item of concern to the NRC.
The issue of identification and resolution of technical issues in a timely manner is recognized and addressed by the licensee's Restart Action Plan, submitted to the NRC on December 22, 1988.
Further
inspector review of the DC voltage problems and the particular reportability concerns are documented in NRC Inspection Report 50-220/89-01.
On November 18, an ENS call was made as a result of the tone alert system being declared inoperable following testing of the offsite emergency sirens.
The tone alert system is operated and actuated by the National Weather Service at Hancock Airport in Syracuse.
For people who live within the 10 mile Emergency Protection lone (EPZ), but are not near a
siren, the tone alert system actuates receivers distributed to these people by Oswego County.
Upon activation of the receiver, the individual is alerted to tune in to the local Emergency Broadcasting System to obtain further information.
The system failed to actuate during the test and was declared inoperable.
The Emergency Planning group notified the control room who then made the ENS call based on degraded offsite response capability.
The system was repaired and subsequently declared operable a short time later.
One'concern the inspectors had in their followup of this event was with the knowledge level of the control room operators with respect to how the tone alert system functions.
This concern was discussed with the licensee and a commitment'as made to provide further operator training in this area and to issue a procedural change which better explains what degraded assessment capability entails.
The inspectors will review licensee actions in a subsequent inspection period.
In Section 15 of the licensee's Rest'art Action Plan, cracking of the spent fuel pool concrete walls and possible leakage from the spent fuel pit is addressed.
The inspectors reviewed this problem with licensee representatives and are satisfied with the evaluations and corrective actions taken, to date, to address the problem.
The licensee plans to perform further boroscopic examinations of the "tell-tale" drains'ump connections and appears to be adequately pursuing the problem for resolution.
The inspectors also performed a physical inspection of the "tell-tale" drains in the reactor building and verified that there presently is no leakage from these drains.
The inspector concluded that the amount of leakage is minimal, closely monitored by the licensee and does not currently pose a safety hazard.
UNIT 2 The unit remained in Cold Shutdown during this'nspection period for the scheduled mid-cycle surveillance and maintenance outage.
The following events occurred during this time period:
On October 25, an actuation of the A (Division 1) Residual Heat Removal (RHR) shutdown cooling subsystem occurred.
Investigation by the
operators found the Engineered Safety Feature (ESF) actuation was caused by electrical maintenance personnel inadvertently contacting heat sink plates of a power source with the metallic armor of a flex cable being pulled through the cabinet.
The maintenance was being performed in an energized cabinet in the back of the control room.
The metal heat sink plates are energized to 24 volts.
The power supply provides
VDC to reactor protection and nuclear steam supply systems circuits.
(Ihen the shielded cable contacted the heat sink plates, the power source unit shorted resulting in the generation of a reactor high pressure trip signal.
This trip signal initiated the isolation of the Division
RHR shutdown cooling system.
Further investigation by the licensee found that this problem occurred twice before as documented in Problem Report (PR) 06754, dated April 13, 1987.
In both instances, shielded cable, being pulled came in contact with energized heat sink plates.
The disposition of PR 06754 recommended warning labels be affixed to alert maintenance personnel of the voltage potential at the cooling fin, in addition to training of electricians on the lessons learned from this type of event.
The inspector determined that the warning signs were not installed and the training appeared to be insufficient to preclude recurrence.
These observations were discussed with the licensee who acknowledged that their corrective actions had not been fully effective and that further preventive actions would be pursued.
The inspectors will review these actions in a subsequent inspection.
b.
C.
On November 22 with A RHR 'in the shutdown cooling mode, the A RHR pump tripped.
Investigation by the operators found that the pump tripped while establishing a red mark-up (tagout) for repair of valve 2RHS*MOV1B.
The pump was restarted.
I Investigation by the licensee determined that the fuse that supplies power to 2RHS*MOVlB valve position indication also supplies power to a
Division 2 relay with contacts in the Division
RHR pump A stop circuit.
Problem Report 08287 was generated by the licensee to determine if this design is acceptable.
Engineering determined that the shutdown cooling mode is not required to be available following a single failure.
The inspector reviewed this evaluation and found it to be satisfactory.
The trip of the RHR pump A due to the mark-up is an example of a personnel error in that the effects of removing the fuses were not fully researched and evaluated prior to commencing work.
On November 30, the'icensee discovered that an incorrect scram pilot solenoid was inadvertently replaced.
The error was traced back to the I&C Planner who prepared the staging documents.
The planner pulled the wrong control rod drive (CRD)
Loop Calibration Sheet and thus copied the incorrect CRD number.
This caused the wrong scram pilot solenoid to be replaced.
The inspector and licensee concluded that this is an example of a personnel error caused by inattention to detail.
The Maintenance Superintendent is conducting an investigation of this incident and plans
to implement corrective action to prevent recurrence.
The inspector will review these actions in a subsequent inspection period.
-
On December 1,
a half reactor scram and Division 2 Alternate Rod Insertion'ARI) Redundant Reactivity Control System (RRCS) trip occurred.
Investigation by the operators determined that the event was caused by a false low reactor water level signal generated from a RRCS level transmitter.
This false signal was produced by a perturbation in the common level transmitter reference line caused by an I&C technician valving in a pressure transmitter (RRS-PT113) for surveillance testing.
Corrective action was to reset the ARI trip after the cause was determined.
The licensee attributed this ESF actuation to a design deficiency.
Future modifications are being engiheered to provide separate sensing lines for the affected level transmitters.
On December 2, the reactor building ventilation system isolated and the standby gas treatment system automatically initiated.
This was caused by an improper tagout which was being applied for modification work on reactor building unit cooler control circuits.
The inspector and licensee consider this inadvertent initiation the result of a personnel error due to inattention to detail.
The inspector will 'review licensee corrective actions in a subsequent inspection period.
On December 3, the licensee discovered a potential wiring error in the Division 1 Automatic Depressurization System (ADS) circuitry.
During troubleshooting the wiring error was located and corrected.
On December 8, the licensee determined that the wiring error rendered Division 1 ADS inoperable since initial fuel loading.
The licensee made a 50.72 notification to the NRC.
A special safety inspection was conducted by the residents to review this event and is documented in NRC Inspection Report 50-410/88-21.
On December 26, Unit 2 experienced a total loss of offsite 115KV power.
At the time of the event, 11SKV electrical power was being supplied to the site by the No.
6 line from Scriba Station.
The second independent 115KV line (line No. 5) had been taken out of service one and one half hours earlier in preparation for planned maintenance.
The cause of the loss of line No.
6 was a fire in a current transformer on offsite breaker R925.
An Unusual Event was declared by the licensee due the loss of r. -site power.
Electrical power was restored via line No. 5.
All stat'.on emergency systems responded properly and all three emergency diesel generators started and loaded, as designed.
The Town of Scriba Volunteer Fire Department and Niagara Mohawk personnel responded to the fire.
The fire was extinguished and the Unusual Event was terminated shortly afterwards.
The inspectors determined that licensee response to this event was timely and professiona.3 The inspectors verified that the events discussed above were properly reported to the Headquarters Duty Officer via the Emergency Notification System, as ap'propriate.
2.
2.1
~Fo11owu on Previous Identified Items (71707,37700,30702,92702),
Unit
(Closed)
Unresolved Item (50-220/84-14-14):
Licensee to correct deficiencies with the Post Accident Sampling System.
During inspection 84-14, the inspector noted that a total of six deficiencies existed with the design of the Post Accident Sampling System (PASS).
Those deficiencies included unreliable position switches, improper application of a pressure',instrument, inadequate pressure rating of a flow element and lack of environmental qualification for the element and a flow control valve, the existence of a dead leg in the sampling tubing, inadequate tubing slope and technical questions concerning the adequacy of the PASS dissolved hydrogen measurement.
To correct the noted deficiencies, the licensee issued modification No.
80-40-1 dated August 30, 1984.
The modification upgraded the PASS to resolve the problems identified during the inspection.
The inspector reviewed modification No. 80-40-1, procedure Nl-CSP-13A, Rev.
1,
"Sampling and Analysis of Reactor Water and Containment Gas Using the Post Accident Sampling System,"
and Preoperational Test Procedure No.
169C, Rev.
0, "Dissolved Gas Modification to the Post Accident Sampling System (PASS)".
In 'addition, the inspector reviewed correspondence between General Electric (supplier of the licensee's PASS)
and the NRC dated January 18, 1984 conce'ming the accuracy of dissolved gas measurement for GE supplied PASS systems.
No problems were noted.
This item is closed.
(Closed) Deviation (50-220/86-03-02):
Licensee to request a Technical Specification (TS) amendment on the operability of the Gaseous Process and Effluent Monitor (TS 3.6. 14.b).
The licensee has incurred numerous'roblems in meeting the requirements, posed by TS 3.6. 14.b which governs the operability of the Radioactive Gas Process Monitor.
The action statement for 3.6. 14.b stated that with less than the minimum number of
, operable monitoring channels.(Technical Specification Table 3.6. 14-2 required),
continued stack gas releases of iodine and particulates were allowe'd provided gas samples were continuously collected with auxiliary sampling equipment.
However, the time required to restore the process gas monitor to service or to place the auxiliary equipment into service was not specified in the TS.
To correct the problem posed by action statement in TS 3.6. 14.b, the licensee requested, and was granted, TS amendment No.
94 which allowed for a period of up to eight hours for the removal of the process gas monitor from service for repairs or for connection of auxiliary gas sampling equipment.
This deviation is close (Closed) Violation (50-220/86-07-03):
Failure to verify the design of one portion of a safety-related Automatic Depressurization System (ADS)
modification.
Inspection 86-07 noted that the design of a modification to the ADS in response to NUREG-0737 Item II.K.3. 1. 18 was not verified.
In addition, the inspector identified adjustable resistors which were to be used in the modification, in conjunction with 55 VAC relays, that were of insufficient power rating to perform their safety function.
The 'licensee corrected the design error in the modification by deleting the relays and the subject resistor from the modification.
This change was accomplished under Drawing Change Request (DCR) LG012.
To improve the design verification process, the licensee modified their design verification procedure as outlined in engineering procedure NEL-027, Revision 2, "Design Verification".
The inspector reviewed the licensee's response to the violation, dated November 5,
1986, as well as procedure NEL-027.
He had no further questions concerning the licensee's corrective actions.
This violation is closed.
(Closed) Violation (50-220/86-07-08):
Failure to perform in-process inspection and to establish holdpoints for fit-up of piping support structural attachments to base plates prior to welding.
During inspection 86-07, the inspector noted that holdpoints were not established and in-process inspection was not performed for fit-up of structural attachments to baseplates for piping supports No. 39-SR2, 39-SR6 and 39-SR7.
The inspector interpreted this finding as an apparent
, violation of Section 3.3 of American Welding Society (AWS) D1. 1.
The licensee's interpretation of Section 3.3 of AWS Dl. 1,"Structural Welding Code", is that the welds did not require fit-up inspection although, as a general practice, the licensee does establish holdpoints for difficult welds, as determined by the welding engineer.
However, the subject welds were fillet welds on carbon steel and were not considered difficult.
The licensee believes that its qualified welding procedures and welders ensured that the welding fit-ups were properly performed.
To ensure that AWS Dl. 1 Section 3.3 requirements will continue to be met, the licensee established a quality assurance surveillance checklist which they plan to use on a sampling basis when reviewing contractor welding activities.
In addition, a recent inspection was conducted in this area and findings were documented in Inspection Report No. 50-220/88-81.
The inspector reviewed the licensee's response to the violation, dated November 5, 1986, as well as Section 3.3 of AWS Dl. 1.
He had no problem concerning the licensee's interpretation of Section 3.3 or their use of a surveillance checklist versus a welding fit-up procedure. holdpoint for this type of weld.
This violation is closed'Closed)
Violation (50-220/86-07-09): As-built configuration of the main steam drain lines did not match the design drawings.
The inspector noted during inspection 86-07 that the installation of drain line No. 39-1-BL and the location of a coupling and support on drain line No. 39-1-A did
-10-not match the design drawing No. C-26843-C (sheet 5).
Furthermore, these deviations were not identified on Design Change Requests (DCRs) for engineering evaluation as required.
The licensee subsequently issued a Drawing Change Request (DCR) to correct the drawing discrepancies.
In addition, a pipe stress analysis was run to confirm that the as-built configuration was acceptable.
No problems were identified by the analysis.
The inspector reviewed revision 5 to isometric drawing C-26843-C, sheet 5 and confirmed that the required changes were made.
This violation is closed.
(Closed) Violation (50-220/86-07-12):
Conduit support was removed without the issuance of a work request.
During inspection 86-07, the inspector noted a support for electrical conduit to hydrogen purge valves 201-32, 201.2-03 and 201.2-32 was dismantled in the vicinity of piping anchor 39-Al.
The removal of the conduit support from its supporting member was not performed via a Modification Work Request (MWR) as required by section 5.4.3 of procedure AP-6.0.
The licensee's response to the violation, dated November 5, 1986, stated that the conduit support was removed due to modification work on the Emergency Condenser System.
Thus, the removal of the support was covered under the work request for the Emergency Condenser modification.
In addition, the licensee's procedures require system walkdowns on completed work to determine its adequacy prior to its acceptance for service.
Therefore, adequate administrative controls existed to ensure replacement of this support.
This violation is closed.
(Closed)
Unresolved Item (50-220/84-15-06):
The unresolved item resulted from plant walkdowns during inspection 85-15 which found that certain portions of the condensate transfer piping system did not appear to have adequate support.
The item was left open 'pending demonstration that the piping in question was seismically qualified.
A region based specialist inspector reviewed the pipe stress analysis in Niagara Mohawk calculation
¹S12-57--P01, Rev.
0, for the condensate system.
Portions of drawings including isometrics were reviewed.
The inspector also considered other items such as assumptions made and load conditions, geometry, load definition, seismic criteria, spot check of computer output stress interaction summary and verification of loads transmitted to the pipe support group for design input.
The inspector found the analysis to be acceptable.
The inspector also reviewed pipe support design calculations.
The inspector found the design calculation for pipe supports to be adequate and acceptable.
However, the inspector identified several minor deficiencies generic to the five calculations he reviewed.
These were:
1) Weld symbols were poorly identified in design calculation sketches for all five supports in questio )
Key plans in calculation sketches are needed to locate the supports.
3) As-Built conditions are not reflected 100% on calculation sketches.
The inspector discussed these findings with the licensee who committed to correct these deficiencies.
These minor modifications will not affect, the seismic analysis results.
The inspector concluded that the actual stresses on piping in the system under review are in accordance with ASME and American Institute of Steel Construction (AISC) Codes for piping and pipe supports, respectively.
This item is closed.
2.2 Uni't 2 In inspection report SO-410/88-19, it was documented that the post-lube pilot valve on the Division 2 EDG was determined to be unqualified.
The licensee informed the NRC of this on November 15, 1988 and preliminary investigation found the cause to be the vendor's drawing improperly classified tha valve as "non-critical" which the licensee interprets as non-safety related (NSR).
Further investigation by the licensee determined that the EDG vendor did not install the correct model pilot valves on both the Division I and II EDGs.
The post-lube pilot valves originally dedicated for use were incorrectly substituted during assembly of the sub-system.
As a result, the Division I and II EDGs were declared inoperable on November 23, 1988.
Subsequently, the unqualified pilot valves were replaced with properly dedicated valves.
The licensee plans to issue Change 6 to Appendix B
Determination ¹88-71 to ensure proper classification of EDG parts from the subject vendor.
The inspector concluded that the licensee overrelied on the vendor's guality Assurrance Program to properly classify the parts.
This appears to be an isolated case and not indicative of a generic problem.
The inspector will closely monitor equipment classification in future
~
inspections.
Plant
~Ins ection Tours (71707,71710,71881)
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
On December 29, the inspector toured the condensate bay area.
This area has undergone an extensive cleanup effort by the licensee.
In the past, anti-contamination clothing was required to go into the area, but with
-12-the cleanup completed, protective clothing is no longer required for general access.
Additionally, the area has been repainted and cleaned and is now well lighted in all areas.
The inspector had one concern related to surveillance checks of fire extinguishers and fire hoses.
He found that many of these devices in the area had not been checked for several months.
Followup investigation revealed that these items are covered by a surveillance procedure for use
, in high-radiation areas and is required to be performed on an annual basis only.
The inspector determined that extinguishers and hoses not in high radiation areas are checked monthly.
In light of the fact that this area has not been a high-radiation area for over a year, and thus readily accessible to perform surveillance checks, and that extensive work and cleanup efforts took place during the time period, the inspector questioned, from a personnel safety standpoint, why the extinguishers and fire hoses were not checked on a more frequent basis as plant conditions permit.
In a meeting with Unit I management on January 4, this item was discussed.
Apparently, this same concern was raised by the General Superintendent during a tour of the area that he made the week before.
The licensee is looking into the 'matter to see if their fire surveillance procedures need to be revised.
The inspector also noted that one of the fire extinguishers, No. 99, was missing from its assigned location.
The inspector reported this to the licensee's fire department for followup.
3.2 Unit 2 On a tour of the unit on December 29, the inspectors observed conditions in the service water bays.
They noted that in the north bay, an excessive amount of leakage was coming out of the "8" service water strainer and was neither being contained nor directed properly to prevent wetting of other equipment in the area.
Specifically, rather than being directed through plastic sleeving to the floor of the bay, much of the leakoff was spilling down from the upper area and flowing down the east side wall over a twenty foot wide area.
Additionally, water was dripping down from the gratings onto equipment, electrical cabling and junction boxes, some of which were safety related.
The inspectors informed the SSS in the control room of their concern, and on January 3,
a subsequent tour of the area showed that much of the leakage had been stopped.
During previous tours over the past several months, the inspectors have noted excessive leakage from the rotating strainers in the service water bay, but leakage was never observed to the degree seen on December 29.
While attempts to divert the leakage in the past have been made, it does not appear that any effort was made to address and fix the cause of the problem.
A subsequent tour of the area four days later revealed that the leakage had been virtually stoppe =13-The leakage problem has existed for quite some time and it appears that the licensee has had adequate time to properly resolve the problem Plant operators pass through the area on a shiftly basis and had many opportunities to call this degraded condition to management's attention Likewise, management tours of the area should have resulted in more timely resolution of the problem.
Discussion with Unit 2 management reveals that while work requests were open and awaiting authorization to initiate repairs, they were given a low priority relative to other outage items.
The. inspector considers this an example of inadequate maintenance prioritization, as the service water bay contains safety related equipment,'ome of which was being wetted down.
Additionally, following repairs to the system, no effort was made by the licensee to ascertain whether any of the safety related equipment in that area was degraded as a result of being wetted.
Overall, licensee response to identify, prioritize and correct the problem was poor.
The licensee informed the NRC that an investigation is underway to review why this condition was not corrected and take appropriate corrective action to prevent recurrence.
General housekeeping conditions in the service water bays will be more closely monitored by the resident inspectors.
Surveillance Review (61726)
The inspectors observed portions of the surveillance testing 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.
I Unit
The inspector observed one of the licensee's contractors, NES, perfoy'ming a liquid penetrant test (PT) on pipe support welds (80-SC-60)
on a
section of containment spray piping.
In addition to the two technicians performing the test, a third NES individual was their to observe the test as part of NES's own required periodic surveillance of work activities.
The inspector questioned the technicians as to the examination method and testing requirements.
The PT was being performed in accordance with NES's procedure for performing liquid penetrant tests, 80A2819, Rev 10, Field Change ¹4.
The PT was required due to work performed on some of the pipe support welds as a result of NCR 1-88-1020, which documented undersized welds for the supports as per CSL ¹82.
The inspector was satisfied with the knowledge level of the technicians and their competency to do the job.
The inspector witnessed the performance of surveillance test NI-ISP-M-201-476, "Hi Drywell Pressure
- Instrument Trip Channel Test/Calibration".
He noted clear procedural adherence by the IAC technicians performing the test and that the technicians were qualified
-14-and knowledgeable of the procedural requirements.
All Measuring and Test Equipment (METE) used was in calibration and properly controlled.
Also, the procedure contained appropriate notes delineating those components which are safety-related and environmentally qualified, as well as requirements for independent verification of critical steps by another qualified IKC technician.
The inspector noted that all test values recorded in the procedure were within the Technical Specification requirements.
No problems with the performance of the test were noted.
Unit 2 The inspector observed, the performance of the operability test on Division 1 emergency diesel generator (EDG) per Procedure N2-OP-100A subsequent to the replacement of the turbocharger post lube pilot valves.
The inspector noted that the operators were very knowledgable of the procedure and had performed the test several times before.
Proper communication between the EDG room and the control room was observed.
The diesel started, came up to speed and voltage and ran loaded for one hour before final data was taken'll data was determined to be satisfactory.
The inspector concluded that the personnel performing the test were experienced and competent.
The inspector noted several minor deficiencies with the EDG; all but one were promptly corrected.
The Division
EDG flywheel timing cover was found not installed and still missing on a subsequent tour of the EDG space.
Licensee management was informed of this finding for their followup of this potential personnel safety hazard.,
On December 29, the inspectors observed portions of procedure N2-OSP-SLC-9001/002 for surveillance testing of the Standby Liquid Control System.
The operators performing the test were knowledgeable of the job requirements and procedures were at the work site and being used.'he final surveillance results were unsatisfactory due to out of specification vibration readings on pump 2SLS-P1A inboard motor bearing.
Additionally, problems were encountered in obtaining required flow rates for the test, but this problem was believed to be due to the ultrasonic flow test device used to measure flow.
'(fork Request 148993 was written on December 30 to troubleshoot the problems encountered.
No concerns were identified by the inspectors'n accordance with Technical Specification 4.6. 1.2.d, the licensee is conducting local leak rate testing (LLRT) on containment penetrations during the current maintenance/surveillance outage.
The testing is bein'g conducted per procedure N2-ISP-CNT, Revision 2, "Local Leak Rate Testing".
During local leak rate testing the licensee has experienced several test failures, many involving residual heat removal system containment isolation valves.
However, the inspector did not note any consistent
-15-pattern among the valves which failed the leak rate testing.
As a result of these failures, the total identified leakage for the containment exceeded the leakage limit established in TS 3.6. 1.2.b, (0.6 La).
To correct this problem, the licensee reworked all of these isolation valves that failed and subsequently retested them.
The inspector reviewed the leak test results on 2RHS-MOV1B before and after the rework to the valve disk.
No problems were noted.
The inspector will continue to review the licensee's LLRT results to verify proper resolution prior to unit restart.
On January 3, the inspector witnessed the performance of an LLRT on valve RHS MOV39A.
The inspector observed that the IKC personnel performing the test were competent and properly adhering to the test procedure.
No concerns were identified Maintenance Review (62703)
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 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.
Unit
On Oecember 16, 1988, the FitzPatrick Nuclear Power Station identified a
potentially generic problem with General Electric (GE) Model AMH 4.76-250-0D circuit breakers used in safety-related applications.
The specific problem involved a "prop-pin" in the breaker operating mechanism which had moved to a position where it prevented trip bar movement and thus breaker operation.
The "prop-pin" movement resulted from a broken spring clip.
The licensee subsequently determined that this problem was unique to circuit breakers refurbished by GE.
The inspector notified the licensee (Niagara Mohawk) of the problems experienced at FitzPatrick for their followup.
Licensee representatives from both Unit 1 and Unit 2 contacted Fitzpatrick for details of the failure.
The inspector determined that the licensee conducted representative sample inspections of their respective unit GE circuit breakers.
Similar GE breakers at Unit 1 are vertically mounted and thus are not susceptible to the same type failure.
None of the breakers inspected showed evidence of this problem.
The similar type breakers at Unit 2 have never been refurbished.
Unit 2 breakers examined show no indication of this problem and the proceduralized periodic maintenance
-16-inspections (for both units) specifically check for this type of failure.
The inspector had no further questions.
5.2 Unit 2 The mid-cycle outage'end date is dependent on completion of local leak rate testing (LLRT) of containment isolation valves.
The original outage end date was scheduled for December 12, 1988 and is currently projected for completion by the end of January 1989.
The inspector attended several of the morning outage meetings and observed that the attendees were generally well prepared and aware of system status.
During magnetic particle inspection of the main generator end coupling conducted. on November 28, the licensee found several linear indications which did not meet the acceptance criteria.
These unsatisfactory linear indications required that the coupling be replaced.
Mith the assistance of General Electric, a replacement coupling was located at PSE&G's Salem/Hope Creek site.
This coupling was transported to a General Electric facility in New Jersey where it was cleaned, blue checked and machined to ensure compatability.
The licensee is investigating the cause of the linear indications and suspects that it may be related to heat treatment at the factory.
The replacement coupling has been installed on the generator rotor.
Portions of the replacement effort were observed by the inspector.
No discrepancies were noted.
At the end of the last inspection period, the licensee had completed the inspection and polishing of the stem on valve RCS*MOV18B and re-installed the bonnet to the valve.
Subsequently, HOV18B was manually cycled and slight resistance between the stem and the new single packing gland design (carbon ring) was noti'ced.
After the valve was cycled through this area several times, the entire length of.the stem passed through the gland freely.
The valve was then satisfactorily cycled usi'ng the motor operator
.
The licensee consider s the valve available for use.
The inspector considers the licensee repair activities were well planned and executed.
On a sample basis, the inspectors directly examined portions of selected safety system trains to verify that the systems were properly aligned in the standby mode.
The following systems were examined:
Unit 2 Low Pressure Core Spray A Train of Low Pressure Coolant Injection No concerns were identified by the inspecto ~Ph aical
~Securit Review (71709)
The inspectors made a comprehensive tour of the Central Alarm Station (CAS), Secondary Alarm Station (SAS), Tactical Suppo'rt Operations Center.
(TSOC),
and access control stations with the Director of Nuclear Security Compliance.
The entire protected area was walked down= and no concerns were identified.
Some positive attributes noted were:
adequate security guard force manning; Security has it own Instrumentation and Controls staff; frequent rotation of guards in the CAS and SAS to prevent inattentiveness; and strong willingness to improve as evidenced by their quick response to identified deficiencies.
A routine, unannounced physical security inspection by specialists inspectors was conducted between September 26-30, and the results were documented in Inspection Report Nos.
50-220/88-30 and 50-410/88-29 issued on November 18, 1988.
One inspector finding requiring clarification was the observation that the licensee's Security Director was of the opinion that in lieu of an Emergency Notification System (ENS) call to NRC Headquarters, the resident inspector could be notified.
The inspector determined that in response to the NRC regional effort to reduce the number of safeguard notifications, the licensee's Security Director still adheres to the one hour reporting requirement to NRC Headquarters found in
CFR 73.71.
If reportability of an event is in the process of being evaluated and is expected to take longer than one hour, the NRC Resident Inspector will be notified within one hour.
If the licensee determines the event is reportable, they will then immediate,ly notify NRC Headquarters via the ENS.
The inspector concluded that the one hour safeguards reporting requirement of 10 CFR 73.71 is being properly implemented by the licensee.
On November 17, 1988, the NRC Executive Director for Operations issued a
letter explaining the new rule on announcing the presence of an NRC inspector on site.
The new rule ensures the presence of an NRC inspector, who has been properly authorized facility access, is not announced or otherwise communicated by Security to the station employees.
This letter has been discussed with both Unit Superintendents and with Security Department management.
While touring'nit 2 on November 25, an inspector became concerned over the appearance of a security guard posted outside the control room.
The guard was not posted for access control, but rather compensatory reasons related to cable penetrations into the control room.
The inspector was concerned about the fact that the guard appeared,to be having a hard time keeping his eyes open.
Although the guard was not sleeping, he appeared to be less than fully alert.
The inspector informed the Station Shift Supervisor in the control room, as well as the Unit 2 Security Supervisor of his observation and concer The response by site security to the inspectors concern was rapid, comprehensive and fully satisfactory.
Site security initiated an internal investigation into the matter and later met with the resident inspectors to discuss their findings,and proposed corrective actions.
The s'ecurity organization acknowledged that the guard in question was less than ful'ly alert.
They also determined the causes for the inattentiveness and took rapid compensatory actions.
They found that one of the reasons for the incident was that the security force had been working twelve hour shifts for several months due to both units being in an outage and due to security system maintenance activities requiring additional compensatory action.
Also, the guard observed by the inspector was in the last hour of his twelve hour watch.
A measure instituted by Security in response to this problem was to require Security supervisors to perform hourly tours of all guard stations.
The inspector noted that the guard force returned to eight hour shifts the following weekend as a result of increased manning.
Additionally, other nuclear utilities were queried over the NUCNET system for information regarding methods they use to maintain guard attentiveness.
The security organization also held several meetings which resulted in the promulgation of a new Security Procedure S-SAP-8. 1,
"Compensatory Post Communication Log and Sign-In Log", which requires that when guards are posted at compensatory posts, they must sign in on a log sheet at the post, as well as call in to the SAS every half hour.
Additionally, the SAS must record all communications received from compensatory posts with the list being reviewed shortly after midnight by the "A" Line Site Supervisor.
The procedure also calls for other measures by guard force members and supervisors to ensure guard attentiveness.
Overall, the resident inspectors are satisfied with the licensee's response to this incident and of the corrective actions taken.
The inspector consider this an isolated event and not a generic problem at the site.
During an earlier NRC specialist inspection (50-220/88-30 and 50-220/88-29)
the inspectors identified a concern with the Station Security Plan regarding vital equipment access control at Unit 1.
The inspection determined that this issue is currently being pursued to resolution by the licensee and,NRR technical reviewers.
This item will remain unresolved (50-220/88-20-02).
Licensee Rerriew of ~Startu Neutron Source
~Siren tir (30702,71707)
Due to the extended outage at Unit 1 and the resultant decay of intrinsic neutron source strength, the licensee performed an evaluation of the projected source strength prior to commencement of Cycle 10 operation.
Using conservative assumptions, the licensee has estimated the minimum
-19-source range detector count rate will be greater than three (3) counts per second (cps) until December 1989.
The inspector reviewed the licensee's evaluation ( Internal Correspondence NMP40393, dated January 3,
1989) which conservatively assumes that the neutron source strength will decay with a 163 day half life.
The primary intrinsic neutron sources consist of spontaneous fission of Curium 242 (163 day half life) and Curium 244 ( 18. 1 year half life).
Based upon an observed 12 cps 14 months after the 1982-1983 shutdown for recirculation piping replacement and mathematical projections, the 163 day half life should maintain the source range counts greater than three cps until December 1989.
Actual source range counts should be considerably higher due to contributions from Curium 244.
The inspector had no further questions.
~Meetin s
(30702)
On December 5,
1988, Mr. E. Menzinger and other members of the NRC staff met with Mr. L. Burkhardt, Executive Vice President, and members of his staff at the station.
The purpose of the meeting was to make initial introductions of Region I NRC staff to the new Executive Vice President, NMPC, and to discuss.licensee progress towards submission of the Nine Mile Point Unit 1 Restart Action Plan.
On December 22, 1988,'icensee senior management met with the NRC staff in the Region I office to formally present the Nine Mile Point Unit 1'estart Action Plan.
Details of this meeting were summarized and documented by a separate report (reference Docket No. 50-220, Meeting Summary, dated January 6,
1989.
Assurance of ~unlit
~Summer (30702,30703)
The inspector notes that the increasing trend of personnel errors documented in the last inspection period has not improved.
During the current inspection period, three personnel errors occurred during the work release process in Unit 2.
These errors were primarily caused by inattention to detail.
Licensee management is implementing corrective action to prevent recurrence.
This area is of particular concern to the NRC staff and will be closely monitored to ensure the adequacy of the corrective action'.
The corrective action taken in response to the Unit 1 Flat Bed.Filter Room (which is a locked High Radiation Area) door which was found unlocked appears to be very thorough.
Inadequately contained leakage from the service water system and inappropriately prioritized maintenance on this system was a concern to the inspectors.
It -appears that there was a lack of attention to this gradually degrading condition by the operators and station management supposedly touring this spac The repeat problem involving the grounded power supply heat sink plates and shielded cable pulling indicates ineffective corrective action and warrants further licensee investigation.
The inspector observations regarding the seismic event on November 25 and the tone alert system failure on November 18 indicate some minor operator training oversights.
11.
Exit M~eetin s (30703)
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'eport and discussions held with licensee representatives, it was determined that this report does not contain Safeguards or
CFR 2.790 information.