IR 05000220/1991012

Insp Repts 50-220/91-12 & 50-410/91-12 on 910623-0727.No Violations Noted.Major Areas Inspected:Reactive Insp of Plant Operations,Radiological Controls,Maint,Surveillance, Security,Engineering & Tech Support & Safety Assessment

ML17058A943
Person / Time
Site:	Nine Mile Point
Issue date:	08/23/1991
From:	Roxanne Summers NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17058A941	List: IR 05000220/1991012 ML17058A939
References
50-220-91-12, 50-410-91-12, NUDOCS 9109040014
Download: ML17058A943 (48)

Text

Report Nos.:

Docket Nos.:

License Nos.:

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

91-12; 91-12 50-220; 50-410 DPR-63; NPF-69 Licensee:

Niagara Mohawk Power Corporation 301 Plainfield Road Syracuse, New York 13212 Facility:

Location:

Dates:

Nine Mile Point, Units 1 and 2 Scriba, New York June 23 through July 27, 1991 Inspectors:

W. L Schmidt, Senior Resident Inspector R. R. Temps, Resident Inspector R. A. Laura, Resident Inspector Approved by:

Robert J. S mers, Acting Chief Reactor Projects Section 1B Division of Reactor Projects

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f plant operations, radiological controls, maintenance, surveillance, security, engineering and technical support and safety assessment/quality verification activities.

R~giil: See Executive Summary.

9109040014 9i0826 PDR ADOCK 05000220

PDR

EXECUTIVE ARY Nine Mile Point Unit 1 and Unit 2

NRC Region I Inspection Reports Nos. 50-220/91-12 and 50-410/91-12 June 23 - July 27, 1991 Plant ratio Unit 1 operator and management performance was good during this period. This was evidenced by close monitoring and subsequent plant shutdown due to increasing unidentified drywell leakage.

During the shutdown, an automatic reactor scram occurred due to a small pressure spike while operating in the intermediate range.

An unresolved item (220/91-12-01)

was identified regarding a repetitive problem with the controls over the 115 KV offsite power supplies shared between Unit 1 and FitzPatrick, Operator performance at Unit 2 was mixed, while management was aggressive and addressing problems.

The plant remained at power throughout the period despite operational problems with the feed pumps.

An unresolved item (410/91-12-02) was opened concerning the inoperability ofa secondary containment unit cooler; NMPC had identified that the service water supply valve to the unit cooler was left shut due to failure to adequately control valve status during a modification evolution.

Radi I i l ontro Radiation protection management responded well to a self-identified deficiency during the decontamination of a control rod blade crusher at Unit 1.

AtUnit 2 an instance ofpoor housekeeping was observed in the service water pipe tunnel. Also poor radiation protection response to an alarming portable airborne radioactivity monitor was identified by the inspectors during a tour of the reactor building. Unit 2 radiation protection management took aggressive actions to address both performance issues.

in n n irv ill nce Management oversight and execution of a planned unscheduled outage at Unit 1, due to unidentified drywell leakage, was very good.

No safety concerns were identified during inspection of routine maintenance and surveillance activities at both units.

ecurit The security department was observed to implement proper vital area door alarm responses and personnel searche Executive Summary (Continued)

'n ineerin and Technical Su ort An unresolved item (220/91-12-03) was identified regarding the possible effects as a result of potential clogging of the fuel oil filters on the Unit 1 emergency diesel generators.

An unresolved item (410/91-12-04) was identified concerning buildup of silt/corrosion products in Unit 2 safety related unit coolers.

An unresolved item (220/410/91-12-05)

was identified concerning the unauthorized use of temporary modifications at Unit 1 and the control of temporary modifications installed by procedures at Unit 2. Also, minor deficiencies in control of Unit 1 drawing changes were identified.

Safet Assessment/

ualit Verification Two Unit 1 root cause investigations were found to be thorough and well documented.

One Unit 2 licensee event report and one special report were reviewed and found to be acceptabl TABLEOF CONTENTS 1.0 SUMMARYOF FACILITYACTIVITIES 1.1 Niagara Mohawk Power Corporation Activities...............

1 ~2 NRC Activities

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1.2.1 Inspection of Deficiency Reporting Systems, Piping Erosion and Corrosion Program and Radiological Water Chemistry 1.2.2 Fitness for Duty Inspection............... '........

1.2.3 NRC Staff Approval ofHigh Pressure Core Spray Injection Nozzle Inspection Plan

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2 2.0 PLANT OPERATIONS (71707, 71710)........................

2.1.1 Control Room Observations 2.1.2 Plant Shutdown to Identify and Correct Unidentified Drywell Leakage; Automatic Reactor Scram in the Intermediate Range 2.1.3 Inadvertent Reactor Building Emergency Ventilation Actuation 2.1.4 Turbine Control OilLeak......... ~..............

2.1.5 115KV Offsite Power Line No. 3 Outage..............

2.1.6 Engineered Safety Feature System Walkdown............

2.2.1 Control Room Observations 2.2.2 Service Water to Safety-Related Unit Cooler Left Inadvertently I o ted so ted olated............ ~......................

2.2.3 Remote Shutdown Panel Mispositioned Switch

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3.1.1 Radiation Protection Management Followup on Potential Overexposure 3.2.1 Response to Alarming Portable Airborne Radioactivity Monitors..

4.0 MAINTENANCE(62703)

4.1.1 Shaft Driven Feedpump Feedwater Flow Control Valve Damage

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5.0 SURVEILLANCE(61726)

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12 6.0 SECURITY (71707)

7.0 ENGINEERING AND TECHNICALSUPPORT (71707)

7.1.1 Control of Drawing Changes.........

7.1.2 Emergency Diesel Generator Fuel Oil Filter 7.2.1 Service Water System Difficulties......

7.3 Temporary Modification Controls (Units 1 and 2)

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Design Review

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8.0 SAFETY ASSESSMENT AND QUALITYVERIFICATION(92700).......

8.1 Review of Licensee Event Reports (LERs) and Special Reports......

9.0 MANAGEMENTMEETINGS........................ ~......

• The NRC inspection manual procedure or temporary instruction that was used as inspection guidance is listed for each applicable report sectio DETAII~J 1.0 SUlVPCARY OF FACILITYACTIVITY 1.1 i

ara Mohawk Power o

ti n Activiti During the period Niagara Mohawk Power Corporation (NMPC) operated Unit 1 at near full power until July 18, when a shutdown was commenced to allow identification and correction of increasing unidentified drywell leakage.

At the time of the shutdown, unidentified leakage was indicated at 3.2 gallons per minute (gpm); technical specifications allow 5 gpm before the unit must be shutdown.

Operations department inspection of the drywell indicated that the major source ofleakage was from a reactor building closed loop cooling flange on the ¹14 recirculation pump cooler, with minor packing leakage from a main steam line isolation valve (MSIV) and a recirculation loop discharge valve.

As part of the retest for the MSIV and recirculation loop valve packing work, a pressure test to 900 psig was conducted.

During this test NMPC inservice inspection (ISI) inspectors noted that there was leakage from a tubing weld in the sensing line for the wide range reactor vessel water level instrumentation.

The weld was repaired by an overlay.

At the end of the period the operators were preparing the unit for startup.

NMPC operated Unit 2 at rated power during the period, except when power was reduced to switch feed pumps to allow pump shaft seal replacement and packing repairs to a moisture separator reheater steam supply valve.

During this period, efforts were made to upgrade the service water system by installing removable flanged spool pieces on various unit coolers for system flushing. During performance of these modifications, the NMPC staff and the inspector noted buildup of silt and corrosion products in piping and in several of the unit coolers.

On July 3 the Unit 2 plant manager issued an administrative stop work order to all plant personnel so that supervisors could discuss the importance of attention to detail with their workers.

This was precipitated by the several instances of inattention to detail documented in Inspection Report 91-11 and the unit cooler event discussed in section 2.2.1 below.

1.2 2~22 A

The activities during this report period included inspection during normal, backshift and weekend hours by the resident staff.

There were 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> of backshift (evening shift) and 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> of deep backshift (weekend, holiday and midnight shift) inspections during this perio.2.1 In i n fDeficien Re in tern Pi in Erosion and rr i n Pr m and ai I i

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hmi During the week of July 8 a regional specialist inspection was conducted at both uriits.

Areas inspected included:

the previous use of problem reports and the transition to the deficiency event report system, piping erosion and corrosion, and the engineering aspects of reactor water chemistry. The final results ofthis inspection willbe documented in combined inspection report 91-14 for both units.

1.2.2 Fi nes for Du In i n During the week of July 8 a regional specialist inspection was conducted at both units in the fitness for duty area.

The final results of this inspection will be documented in combined inspection report 91-13 for Unit 1 and 91-15 for Unit 2.

1.2.3 ffA r val fHi hPr sure re ra Inecti nN zzleIn eci nPl n On July 16 NMPC received approval from the NRC staff for a growth acceptance limiton the flaw in the high pressure core spray (HPCS) injection nozzle.

NMPC had requested pre-approval of the crack growth limitto minimize time delays following the UT inspection of the weld scheduled for the next plant shutdown.

The NRC letter also addressed several aspects of the weld overlay process which NMPC has proposed to correct the crack in the event it has grown past the acceptance limit. These aspects dealt with areas that NMPC would have to address for the overlay to be acceptable to the NRC staff.

Specifically addressed were the bases for no post-weld heat treating, an increase of the weld thickness to 0.3 inches and evaluations of weld shrinkages on pipe supports and whip restraints.

The letter further requested that NMPC provide a copy of the proposed weld procedure to the resident inspector at least seven days prior to the start of welding.

2.0 PLANT OPERATIONS (71707, 71710)

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erv ti n The inspector observed that control room activities were well conducted during routine operations and the plant shutdown.

The operators were knowledgeable of plant conditions and ongoing surveillance and maintenance activities, as well as the reasons for lighted annunciated alarm.1.2 Plant h tdown t Identif d

orrec nidentified D well Leaka e. Aut matic ea r Scram in the Intermediate Ran e The operators were observed to perform well during the normal plant shutdown to cold shutdown initiated on July 18 to identify and correct the source of increasing unidentified drywell leakage.

At the start of the shutdown, leakage was 3.2 gpm with a technical specification limitof 5 gpm.

During the previous month, the leakage increased approximately 0.1, gpm per day and was closely trended by operations and management personnel.

The operators also responded well to an automatic reactor scram which occurred due to an upscale trip of the ¹13 and ¹16 intermediate range monitors during the shutdown.

The NMPC post-scram review determined that the trip was caused by a small reactor pressure spike when a two inch main steam line drain valve was shut, which caused a reactivity excursion.

During the shutdown, a drywell entry and inspection was performed with reactor pressure at approximately 500 psig. Leakage was identified as coming from the reactor building closed loop cooling water piping to the ¹14 reactor recirculation pump seal cooler.

Smaller packing leaks were also found on the ¹12 recirculation loop discharge valve and on MSIV 01-01.

In summary, NMPC closely monitored the unidentified drywell leakage and commenced a plant shutdown to identify and repair the leakage prior to approaching the technical specification (TS)

limitof5 gpm. Operator actions following the scram were good and the post-scram review was comprehensive, as observed during the post scram critique.

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t rB ildin Emer enc V nil i nA i n An inadvertent actuation of the reactor building emergency ventilation (RBEV) system occurred on June 29, while removing the refuel floor high range area radiation monitor trip unit during surveillance testing.

The surveillance was stopped and the proper four-hour NRC notification was made pursuant to 10 CFR 50.72.

Using a troubleshooting work request, instrument and control (1&C) technicians identified a blown fuse as the cause of the actuation.

Initially, the cause of the blown fuse was attributed to fatigue from aging. The fuse was replaced and normal reactor building ventilation was placed in servic On July 1 another inadvertent initiation of the RBEV system occurred when the same trip unit was removed during the performance of the same surveillance test.

The test was again stopped and the required NRC notification made.

Investigation revealed that the same fuse blew again.

A thorough inspection of the trip unit wiring revealed a damaged section of ribbon cable. I&C technicians determined that the damaged insulation was most likely the result of removing and re-installing the trip unit from the rack.

The nicked cable resulted in grounds to the chassis, causing the blown fuses and the RBEV actuations.

The NMPC root cause analysis concluded that the second event resulted from a failure to correctly identify and take all the necessary corrective actions following the first event.

The NMPC assessment stated that a more thorough inspection should have been performed in response to the first actuation.

The safety significance of these events was low because the RBEV initiation did not impact system operability or availability.

2.1.4 Tur ine ntrol Oil Leak The Unit 1 plant management took good aggressive actions to assess the impact of continuing plant operations with a significant control oil leak (approximately two gpm) in the mechanical hydraulic control (MHC) system of the main turbine.

The leak was detected by an operator on rounds.

The leaking oil, which was contained in a cabinet enclosure and drained back to the oil sump, did not present an apparent fire hazard.

Control oil pressure and control valve positions remained stable and the leak did not pose any noticeable operational problems.

The source of the leak could not be initiallydetermined because ofthe large amount ofoil spraying inside the cabinet.

Plant management met to determine ifsafe plant operations could continue with the oil leak and initially concluded that a controlled shutdown was prudent to prevent an unnecessary plant

transient in the event the size'of the leak increased.

However, during shutdown preparations, NMPC identified that the leakage was coming from a fitting, rather than a tubing leak, and obtained information from the vendor that supported continued operation with the leak at minimal risk. NMPC decided to continue plant operations with the oil leak and repair it during the next shutdown.

Unit 1 management took a cautious approach to assess the impact of the control oil leak.

2.1.5 11 KV ffi e P wer Lin N

NMPC was not effective at ensuring that the status of the 115KV emergency offsite power supplies, common to both Unit 1 and FitzPatrick Nuclear Power Plant, was adequately known.

On July 3 NMPC power control central notified the Unit 1 station shift superintendent that the Lighthouse Hillline No. 3 had been returned to service and that the line had been out ofservice of approximately five hours.

This line is one of two 115 KVoffsite power lines shared with the adjacent FitzPatrick plant. The line was de-energized by FitzPatrick operations personnel at the request of NMPC power control central to allow for replacement of insulators.

Due to system design Unit 1 had no available indication of loss of one offsite power line.

Power control

central and FitzPatrick station failed to notify the Unit 1 staff of the line No. 3 outage as had been previously agreed to following a similar incident in 1988.

The failure of the FitzPatrick staff to notify Unit 1 was addressed in FitzPatrick inspection report 50-333/91-14.

During the period that line No. 3 was not in service, the Unit 1 operations staff removed the 103 emergency diesel generator (EDG) from service to support corrective maintenance.

Because the unit 1 operators did not know of the line outage they believed that the unit was in a seven day limiting condition for operation (LCO) for the single EDG out of service.

With the one offsite power line lost and one EDG out of service Unit 1 should have been in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> shutdown LCO. Line No.3 was returned before the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> LCO time limitwas violated.

Once aware of the line No. 3 outage, operator and management response was good.

NMPC initiated Deviation Event Report 1-91-Q-0495 to investigate the failure ofpower control central and the FitzPatrick staff to properly notify Unit 1 of the line outage.

The inspector noted that this was the second time coordination problems between Unit 1 and FitzPatrick over offsite power line availability has occurred.

In October 1988, Unit 1 deenergized the other offsite power supply, South'Oswego line No.4 without telling FitzPatrick. This resulted in a short loss of offsite power at both sites when line No. 3 was lost on a fault. The inspector considered that this issue represented an unresolved item (220/91-12-01) pending review ofthe corrective actions taken to preclude recurrence.

2.1.6 n in red fet F

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The inspector conducted walkdowns and verification of system configuration, to ensure that the liquid poison system would perform its safety function.

The inspector utilized Piping and Instrument Diagram (P&ID) C-18019-C to verify that the line-up specified in N1-OP-12 was correct.

Technical Specifications (TS) section 3.1.2 and the Final Safety Analysis Report (FSAR)Section VII.C were reviewed to ensure compatibility with the installed system and procedure Nl-OP-12.

No significant safety issues were identified, however, several minor concerns were identified as discussed in the inspector's findings below:

No hardware discrepancies which might degrade operability of the system were

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identified.

The system valve line-up in procedure Nl-OP-12 matched plant drawings and the as-built configuration.

The inspector verified the identification on drawings and inclusion of all appropriate instrument root valves in the valve line-up sheets.

No discrepancies in valve positions were note Three minor discrepancies in procedure Nl-OP-12 were noted:

Step 3.8.2 referenced an incorrect valve identification number, 41-01 vice 42-01 due to an apparent typographical error.

A temporary change notice was subsequently issued to correct this.

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The system fill and vent methodology in Section E.3 did not vent any air collected in the upstream side of the diaphragm seal for the pump discharge pressure transmitter IL-04. This section ofpiping is a dead leg where trapped air could potentially affect the pressure transmitter readings.

This was discussed with the operations support supervisor who committed to review the potential concern and make changes as necessary.

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Procedure Nl-OP-12 stated that the relief valves were set to open at a pressure of 1400 psig, which was consistent with FSAR section C.2.

However, the inspector noted that document change request 1-89-900-LS-018 posted on PAID C-18019-C showed the relief valve setpoints were changed to 1500 psig.

After further review, the inspector determined that the setpoint for the relief valves had been changed to 1500 psig, but the applicable sections of N1-OP-12, and the FSAR were not updated.

The operations support supervisor agreed with the inspector's findings.

Procedure Nl-OP-12 was changed to properly reflect the relief valve setpoint of 1500 psig, and a change to FSAR section C.2 was initiated.

In summary, the safety system verification of the liquid poison system found that all valves were in their correct positions and the system was fully operable.

Some minor deficiencies with procedure Nl-OP-12 were identified and NMPC took appropriate corrective actions.

iinit2 2.2.1 n r 1R om erv i n The inspector observed that control room activities were well conducted during routine operations and during power reduction to allow the transfer of feed pumps.

Operators were knowledgeable of plant conditions, except as noted below in section 2. f,

2.2.2 ervice Water to Safe-Rel t nit Cooler Left Inadvertentl I

lated On July 2 while performing the monthly service water valve'position verification (2-OSP-SWP-M001), operators identified that the service water inlet and outlet valves to unit cooler HVR-UC404D were mispositioned.

Specifically, the inlet isolation valve was found shut vice in its required open position, and the outlet valve was found at 40 degrees open vice in its required position of 55 degrees open, Thus the cooler was not receiving water flow and could not have removed any heat.

This resulted in a condition whereby standby gas treatment (SBGT) train B would not have been able to complete a secondary containment draw down within the time required by accident analysis.

Further NMPC investigation determined that the operations department did not properly control the valves on a secondary containment unit cooler, leaving the cooler without flow when it was returned to service.

Unit 2 TS interpretation %5 provided guidance to be followed when dealing with these secondary containment unit coolers and their relation to the operability of SBGT to provide the required SC draw down.

The TS interpretation required that when one SC unit cooler was out of service the associated SBGT train (powered from the same division of emergency power) be declared inoperable and a seven-day shutdown LCO entered.

In this instance, Unit 2 operations personnel were unaware of the fact that the unit cooler, and therefore SBGT train B, was inoperable; thus the TS LCO was not entered.

NMPC's investigation revealed that the cooler was inoperable for greater than seven days, therefore, this TS LCO for an inoperable train of SBGT inoperable was not complied with. Further, NMPC investigation showed that, in two instances, the 24-hour cold shutdown LCO requirement for both SBGT trains inoperable was not met.

Specifically, SBGT train A was removed from service effectively twice; once when the train was inoperable and once when its associated emergency diesel generator was inoperable.

Upon discovery ofthe mispositioned valves on July 2, the valves were immediately repositioned to their required positions and the unit cooler restored to operability. Unit 2 management and the residents were informed and deficiency event report (DER) 2-91-0477 was initiated to document the problem.

Licensee event report (LER) 91-16 willdiscuss this event and the result of NMPC's root-cause investigation.

LER 91-16 was scheduled to be issued after this report period.

The operations department determined that the service water valves became mispositioned on June 17, during valve manipulations in support of a modification to install service water flush connections on the unit cooler (flush connections were being installed on reactor building unit coolers under the modification process).

Operators established a protective markup for the work which closed and tagged shut service water inlet and outlet isolation valves.

However, due to leakage past the isolation valves, the markup was terminated and the job canceled for the time being.

However, the valves were not repositioned to restore the cooler to service.

NMPC has been unable to determine exactly why the valves were left out of position.

Review of the situation was hampered because the markup in question was unavailable for review since the practice at the time was to dispose ofcanceled/voided markups.

The personnel involved did not clearly remember ifthe tags were hung or not. It was clear, however, that configuration control on the valves was lost during processing of the marku The inspectors determined that NMPC's response to the event was proper. Allshift crews were briefed by the operations superintendent and/or supervisor regarding the event and the need to ensure positive control over component configuration. Additional guidance was provided on the handling of aborted or voided markups which included; performance of restoration lineups for any repositioned valves; and saving and filing of the markups.

However, the inspector was concerned with the lack ofpositive control over the position of the SW valves.

This particular event was especially noteworthy in lightofprevious configuration control problems at both units for which enforcement actions were taken; blue markup issues at Unit 1, safety-related unit coolers found out of service at Unit 2. This was considered an unresolved item (410/91-12-02)

pending issuance of LER 91-16 and NRC review of NMPC's final root-cause evaluation and long-term corrective actions.

2.2.3 Rem te hutdown Pan l Mi iti ned wi ch On July 3 operations personnel, while on tour in the remote shutdown panel rooms, noted that the control switch for one of the main steam relief valves (MSS*PSV127A) was in the open position.

Since control of the valve was not at the remote shutdown panel at the time of discovery, there was no impact on plant operation as a result of the switch being out ofposition.

However, had the condition gone unnoticed prior to the transfer of control to the remote shutdown panel the relief valve would have opened.

Both remote shutdown panels were inspected to ensure no other mispositioned components existed.

Two other components, none having any immediate plant impact, were identified as being out ofposition. NMPC initiated DER 2-91-Q-0479 to document the event.

Additionally, Unit 1 operators were informed and performed a walkdown of the Unit 1 remote shutdown panels which did not reveal any mispositioned switches.

Unit 2 operations was developing a periodic surveillance to ensure that switches on the shutdown panels remain properly aligned since there was no method in place at the time of discovery.

How the components became mispositioned was unknown. The inspectors determined that NMPC's handling ofthis event and planned corrective actions were adequate.

3.0 RADIOLOGICALCONTROLS (71707)

gni~1 Normal inspector tours of the radiologically controlled areas identified no deficiencies or weaknesses with the radiological practices. being utilize.1.1 Radi ti n Pr tection Mana ement F ll w n Potential verex osure During this period, NMPC identified and briefed the resident inspectors of a potential overexposure during decontamination of the control rod blade crusher machine.

The machine was located on the refuel floor of the reactor building and was being used to reduce the size of spent control rods located in the spent fuel pool in preparation for shipping.

A small piece of high dose rate material (40 R/hr) was picked up on a swipe of the control rod blade crusher performed during a survey by a radiation protection technician.

The technician handled the swipe for approximately 20 seconds following pick up of the material.

Upon discovery of the high rose rate material, the technician secured the decontamination effort and informed radiation protection management.

Radiological Occurrence Report 1-91-026 was generated to investigate the matter.

Several concerns and issues were identified by NMPC with the way the high dose rate material was controlled and the way the decontamination effort was conducted.

The inspector reviewed the corrective actions taken and found them to be prompt and thorough.

No regulatory or NMPC administrative radiation limits were exceeded by the radiation protection technician performing the swipe or by the decontamination crew.

A Region I based radiation protection specialist reviewed the event and identified no additional concerns.

gni~2 Overall, radiation protection (RP) activities observed were good, however, the inspector noted one example ofpoor radiological housekeeping in the contaminated portion of the service water pipe tunnel.

In this instance there was a large amount of used anti-contamination clothing left, on a set of stairs because the proper disposal barrels could not be reached.

NMPC took good and prompt action to resolve this issue.

Unit 2 plant management review of this issue indicated that personnel knew of the problem but had not taken actions to correct it.

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i tivit M nitor The inspector determined that radiation protection personnel did not respond properly when a reactor water cleanup system packing leak caused increased airborne radioactivity levels in the reactor building. The inspector and radiation protection management determined that this was due to a false assumption that the increased airborne levels were due to rado While touring the reactor building on July 15, the inspector observed an alarming portable airborne radioactivity monitor (AMS-3), on elevation 261 near the elevator, which indicated approximately 1 x 10E4 counts per minute (cpm) with an increasing trend shown on the graph paper.

The inspector left the area and immediately contacted the RP control point.

During further touring of the reactor building the inspector noted another AMS-3 monitor alarming on elevation 215.

The inspector again left the area and contacted the RP office and was told that the alarms had been coming in since the morning and that an investigation was underway.

While leaving the radiologically controlled area the inspector discussed the alarms with an RP technician, who stated that it was due to radon buildup because of a thermal inversion.

The inspector then proceeded to the control room, where it was observed that the below the refuel floor ventilation exhaust radiation monitor was alarming at its high setpoint.

The inspector discussed the conditions with the station shift superintendent (SSS) who then called RP to verify that actions were underway.

The inspector then proceeded to the RP office where the results of a high volume air sample were being reviewed.

These results indicated that the airborne activity was due to a reactor coolant leak, not radon, and that the airborne activity was approximately 3% ofa cumulative maximum permissible concentration (MPC) for the activation products found.

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Further RP and operations investigation identified a manual reactor water cleanup (RWCU) valve with a packing leak.

The valve was back seated and the situation returned to normal.

The highest concentration observed was 6% of one MPC near the RWCU room.

Through discussion with RP management the following day, the inspector learned that the air sample analyzed above was the first sample taken that day and that the alarm setpoint on the AMS-3 monitors were increased, since up to that point RP technicians assumed that the alarms were due to radon.

On July 24, a memo was issued from both plant managers to all site personnel discussing the event and the required responses (i.e., leave the area) for airborne and radiation alarms.

On July 26, RP management issued a memo which provided adequate corrective action for this event.

Radiation protection management was effective in their review of this event and took adequate actions to prevent recurrence.

4.0 MAINXI~WANCE(62703)

The inspector observed and reviewed selected portions ofpreventive and corrective maintenance to verify compliance with regulations, use of administrative and maintenance procedures, compliance with codes and standards, proper QA/QC involvement, and equipment alignment and retes t

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iinit I The following activities were observed:

Troubleshoot and repair the ¹15 recirculation pump motor generator set starting circuit.

Disassembly and rebuild of the ¹11 control rod drive pump due to vibration problems.

Preventative mechanical maintenance to open and inspect the 111 containment spray heat exchanger for biofouling. No notable heat exchanger fouling was identified.

The inspector observed that the maintenance above was conducted using procedures.,The troubleshooting activities were well conducted.

No safety concerns were identified during the above maintenance observations.

4.1.1 haft Driven Feed um Feedwater Flow Control Valve Dama e Following the July 18 plant shutdown, NMPC disassembled the No. 13 north feedwater control valve for inspection due to suspected wear related problems.

Upon disassembly, it was found that the locking pin that prevents the stem from unscrewing from the disc had eroded away.

This resulted in stripping of the threads between the disc and stem and subsequent free play in the valve internals.

The No. 13 south control valve was also disassembled and was found to be in satisfactory condition.

Management and engineering involvement in developing a repair plan was noted to be very good.

The valve vendor was brought in to assist in the repair effort. A minor modification was made to the locking pin to ensure it will stay in position and a new set of valve internals was installed.

The inspector noted the repair activity was properly controlled.

A stem fracture on the south feedwater control valve (parallel to this valve) caused a feedwater system transient and forced plant shutdown in 1987.

A DER was initiated in response to these events to review the root cause and develop corrective actions to address the flow induced vibrations in this valve arrangement.

gni~2 The following activities were observed:

Removal, inspection and cleaning of service water (SW) strainer 4B in accordance with procedure N2-MPM-SWP-SA513, Revision 2.

The inspector observed removal and.

liftingof the strainer from its housing and removal from the SW bay for inspectio Removal and inspection of the SW check valve downstream of SW pump B.

While independently verifying proper isolation of the system to support the ongoing work, the inspector noted that there was no tag hanging on the B pump's inlet isolation valve 2SWP*V10B.

Upon checking the markup logbook in the control room, the inspector identified that the component should have had a red markup tag on it.

The SSS was informed of this discrepancy and the missing red tag was found on the SW bay floor.

A replacement tag was issued and the markup reverified.

The inspector determined that appropriate actions were taken.

Repacking ofthe low pressure core spray valve CSL*MOV107. Maintenance personnel were unable to remove all of the packing as the lantern ring was rusted in place and could not be removed.

The maintenance supervisor was informed and the decision made to repack what had been removed and to monitor the valve for leakage.

The inspector noted that for the maintenance activities observed above the work was performed in accordance with procedures, and maintenance supervision involvement was good. No safety concerns were identified during the above maintenance observations.

5.0 SURVEILLANCE (61726)

The inspector observed and reviewed portions of completed surveillance tests to assess performance m accordance with approved procedures and Limiting Conditions for Operation, removal and restoration ofequipment, and deficiency review and resolution. The following tests were reviewed:

@nit i N1-ST-Q6E, Containment spray quarterly operability surveillance test.

N1-CSP-25M, Quarterly service water effluent sample analysis.

Nl-ISI-LK-102, Rev. 00, Reactor pressure vessel 900 PSI leakage test.

This leak test was performed as a post-maintenance test for valve packing maintenance located in the drywell. Several minor leaks were identified during the leak test.

The surveillance tests observed above were properly conducted.

The conduct ofthe 900 psi leak test was considered to be proactive, preventing the specific need to do post-maintenance leakage testing during reactor startu.0 SECURITY (71707)

During routine plant tours, the inspector observed good security force response to vital area door alarms.

Searches of personnel entering the protected area were conducted properly.

7.0 ENGINEERING AND TECHNICALSUPPORT (71707)

@nit i 7.1.1 ontrol of Drawin Chan es The inspector reviewed six safety-related system drawings posted in the field and in the control room to ensure that as-built information was properly being updated.

This review showed that with minor exceptions, discussed below, the drawings were adequately updated.

However, a practice ofposting proposed modifications on drawings was found to be confusing. Further, the method used for posting the changes did not ensure that the "redlining" of the drawing was done at the time of posting (i.e., the posting would be done by one person and the redlining by another).

"Redlining" is the process used to update drawings prior to issuance of a new drawing revision, by inserting the applicable change on the drawing in red ink. The following drawings were reviewed:

18026C, sheets one and two of two, EDG piping and instrument drawing (P&ID). All drawing changes requiring redlining were properly installed.

However, four document change requests (DCRs) attributable to planned modification 85-14 were posted against both the control room and EDG room drawings, and the modification was never installed.

C18018C, sheet one of two, shutdown cooling P&ID; two DCRs were properly posted, redlined and referenced on the control room and in-plant copies.

On sheet two of two, one DCR which had already been incorporated was left posted on the in-plant drawing.

18019C, standby liquid control P&ID. While the five DCRs posted against this drawing in the field were also referenced on the control room drawings, one was not properly redlined.

In this instance a DCR was issued to document the changing of the pump discharge relief valve setpoints from 1400 psig to 1500 psig, but neither copy of the drawing was redlined to incorporate the change.

C18017C, emergency cooling P&ID;fourDCRs were properly incorporated in the control room and in-plant drawings.

C18012C, containment spray P&ID; no DCRs were posted to this prin Inspector review indicated that the system for updating drawings, while effective for the most part, was cumbersome and left room for errors.

Further, the posting of drawings before they were approved as-builts could lead to confusion when trying to assess actual system configuration. NMPC has noted several of these concerns internally in the past.

The operations support manager stated that the drawing control program was under review and changes to correct these types of problems were underway.

The overall assessment was that there was minimal safety significance to the identified problems and that NMPC was taking action to resolve the drawing control process problems.

7.1.2 mer en Diesel enerator Fuel il Filter De i n Review During a walkdown of the emergency diesel generator (EDG) fuel oil system the inspector noted that the fuel oil system was not designed with differential pressure indication or alarms to warn the operators that the filters were clogged prior to the EDG losing load due to loss of fuel oil.

Further, the inspector noted that the filter consisted of two elements in parallel with both elements continuously in service and that no ability to switch to single element operation to allow for replacement of a clogged element existed.

The EDG system engineer provided a detailed description of the operation of the EDG filtering system, which was equipped with two sightglasses.

When the first sightglass is full, it indicates that the machine is receiving fuel oil by monitoring the return fiow from the injectors.

The second sightglass is downstream of a relief valve in the filtersupply header and would be fullifthe relief valve lifted due to clogging of the filters.

The inspector was concerned because there was no direction given to operators on what should be done ifoil was observed in the second sightglass during operation.

The system engineer stated that the filters were changed out once per cycle and that there was no evidence of clogging.

Operations department management stated that they would revise their operations procedure to provide instruction on operator actions in the event of the filterbecoming clogged.

Further the inspector questioned the effect on EDG operation if the relief valve lifted.

The system engineer stated that once the relief valve lifted the machine would not be receiving sufficient oil to maintain design load.

Based on this statement the inspector questioned whether the filtering design was adequate to allow proper operation of the EDGs.

The plant manager stated that a review of the filter design would be conducted by NMPC.

The inspector considered this an unresolved item (220/91-12-03) pending NRC evaluation on NMPC's revie iinit 2 7.2.1 ervi W ter em Diffi l i The inspector identified concerns over the operability verification of safety-related unit coolers.

During modifications to enhance the ability to flush these coolers, which receive service water flow, NMPC observed silt and corrosion buildup on system piping and in the coolers.

Further, NMPC was reviewing the effects of observed microbiologically induced corrosion (MIC) on system piping.

The inspector determined that the ability of these coolers to remove their designed heat load could be affected by the silt and corrosion buildup.

The specific unit coolers provide heat removal to support proper standby gas treatment system draw down of the secondary containment; and operation of safety-related components in the reactor building, service water bays and switchgear rooms.

The inspector reviewed TS interpretation ¹25 in which unit management provided guidelines for which unit coolers were required to be operable to support operation ofthe plant and its systems.

The inspector determined that this interpretation provided good guidance on what unit coolers were required to be operable, and what action was required if they were found inoperable, however, there was no clear definition of what operable meant or the surveillance requirements needed to verify operability.

NMPC has modifications underway which provide flushing paths for the reactor building coolers and which involve removing portions of the supply and return piping and installing spool pieces.

During several of these modifications, performed this inspection period, technical services personnel and the inspector noted corrosion products and silt buildup in piping and heat exchanger tube areas on several of these coolers.

These coolers were designed with constant service water fiow and a modulating fan which controlled the area temperature and actuated on a LOCA standby gas treatment start to cool the building air and provide the required draw down time.

Based on the conditions observed, NMPC was pursuing implementation of an adequate flushing program..

Because of the buildup of silt/corrosion products in the coolers which receive constant flow, the inspector was concerned with the condition of the unit coolers in safety-related switchgear rooms, since their service water flow was either on or off (to support heat removal) with a continuously running fan. The inspector reviewed the current surveillance program on the HPCI switchgear unit cooler, and found that there was no programmatic data taken to verify the heat removal capability ofthis unit cooler. The surveillance program included: monthly verifications of valve positions; cycling of the temperature control valve from the control room to verify operation quarterly; and an 18-month loop calibration of the temperature control loop which normally operates the control valve. In no case was there a verification of adequate water flow with the valve ope Through discussions with the technical services manager, the inspector learned that the operability of these heat exchangers was based on a 75% effectiveness for each cooler.

The inspector has asked NMPC to provide the detailed engineering calculation used to develop this assumption.

The inspector considered the operability of these unit coolers an unresolved item (410/91-12-04) pending further review of NMPC',s calculation, assumption and surveillance testing program.

As part ofthis review, the inspector reviewed temporary modification 90-47 which installed side stream monitors at three locations in the plant for use in the zebra mussel monitoring program.

Two monitors are located offlow point drains in each of the SW bays and one monitor offthe fire water system.

The inspector reviewed safety evaluation D90-215 and found it to be technically adequate.

The inspector also verified that appropriate plant drawings were updated to reflect addition ofthe side stream monitors and that procedure N2-OP-11, which operates the SW system, was updated to reflect the open position of normally closed drain valves.

The temporary modification was determined to be implemented in accordance with station administrative procedures and to be technically sound and thorough.

The inspector had no further questions in this area.

7.3 Tem ra Modificati n n r l ni 1 and 2 The inspector identified problems, of minor safety significance with the implementation of temporary modification controls at both units. AtUnit 1, blowers were installed to cool cabinets without being proper controlled in accordance with site administrative procedures.

At Unit 2, hoses used to supply flushing water to service water radiation monitors, were left installed following completion of the flushing procedure and were not handled as a temporary modification in accordance with site administrative procedures.

iinit 1 During a tour of the reactor building on July 1, the inspector observed that local fire panels 6 and 7 were open with electric blowers discharging into the panels.

It was noted that these blowers were not controlled as a temporary modification in accordance with administrative procedure (AP) 6.1, section 3.7.14, which stated "Temporarily installed ventilation equipment such as fans and blowers used to augment inadequate cooling shall be treated as a temporary modification". Further, during several weekly meetings prior to the identification of this item, the inspector had questioned the installation ofventilation fans on a safety-related electrical panel and in battery rooms, and their inclusion in the TM proces In response to the identification of this condition, the fans were removed.

A DER was written to investigate the installation of the fans.

NMPC issued a lessons learned transmittal to ensure that operations and fire department personnel understand the proper method that should be used when installing a temporary fan. Further, the independent safety and engineering group (ISEG)

initiated a review of the previous temporary modification problem.

iLttit2 The inspector found that flushing water hoses were left installed between the two service water radiation monitors (2SWP*CAB146A and B) and were sporadically left installed on the residual heat removal (RHR) heat exchanger service water monitors (2SWP~CAB23A and B).

'nspector review of NMPC's TM administrative procedure 6.1 and the flushing procedure N2-RTD-130, revision 2 showed that the installation and removal of the hoses was not properly controlled.

AP 6.1 treated a temporary modification installed by a procedure as an exclusion from the normal TM process as long as the procedure received safety review and the TM received adequate verification ofinstallation and removal. The inspector found that the flushing procedure only installed the hoses but never directed their removal.

However, the procedure plant impact section did state that a temporary modification was being performed in accordance with AP 6.1.

The inspector requested that NMPC provide a copy of the flushing procedure generation package.

Review of the procedure technical review check sheet used during preparation of Revision 0, dated September 16, 1987, showed that it was verified that the "procedure removes any jumpers or blocks and restores lifted leads used to effect the work"; when in fact, the procedure did not remove the hoses.

Revision 1 to the procedure was completed in June of 1989 as part of the periodic review and procedure upgrade.

During technical review for this revision, the check sheet was marked N/A for restoration of the jumpers and the statement that indicated the use of a temporary modification in the procedure was added to the plant impact statement.

The technical review conducted on Revision 02 indicated that both the plant impact statement needed to incorporate the temporary modification and the restoration of the temporary modification were N/A.

This issue was discussed during the July 17 weekly meeting with plant management who were reviewing the observation.

At the end ofthe report period the hoses at the service water effluent radiation monitors were still installe nclusion While the safety significance of both of these instances was minor there were several related performance problems in the recent past including: at Unit 1, a non-cited violation due to failure to recognize the tie-in ofa portable demineralized water trailer as a temporary modification and examples of failure to maintain the TM log up-to-date; at Unit 2, use of a portable heat lamp which was required for operability of a containment monitor without it being treated as a

temporary modification. The inspector considered that this issue represented an unresolved item (220/410/91-12-05) pending further NRC review ofthe NMPC temporary modification process.

8.0 SAFETY ASSESSMPfT AND QUALITYVERIFICATION(92700)

8.1 Review of Licen ee Event Re rts ER and S ecial Re orts

~nit 2 The following special report and LER were reviewed and found satisfactory:

Special Report, dated July 12, 1991, concerning a non-valid failure of the Division 1 Emergency Diesel Generator (EDG). During a partial loss of offsite power on May 21, 1991 (discussed in IR 50-410/91-10 and LER 91-12), the Division 1 EDG started.

Operators noticed that the speed of the EDG was oscillating while in the isochronous mode.

On June 12, 1991, a special test was run on the EDG to troubleshoot the emergency governor speed reference circuit.

During this test, oscillations outside TS limits were observed.

Corrective actions were taken to replace three relays in the isochronous operation speed reference circuit.

The contacts were found to have unacceptably high resistance due to oxidation.

As this was a repeat problem with the relays for the Division I EDG (Division II has never demonstrated this problem), long term corrective actions call for the replacement of the present model Agastat relays per a plant change request.

In the interim, periodic surveillance will be performed to identify and allow for correction of degradation in the relays until they are changed out.

The inspector determined that this problem was being dispositioned properly with good corrective actions in place and planned.

LER 91-12, actuation of several engineered safety features caused by a loss of offsite power feed, due to excavation at Scriba Station.

The events described in this LER were discussed in IR 50-410/91-10.

No further concerns were identified as a result of reviewing the LER. NMPC's corrective actions were adequat !

9.0 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 informatio