IR 05000333/1987021

Insp Rept 50-333/87-21 on 870901-1020.Violations Noted.Major Areas Inspected:Ler Review,Operational Safety Verification, Surveillance & Maint Observations,Ie Bulletin Followup & Review of Periodic & Special Repts

ML20236Q501
Person / Time
Site:	FitzPatrick
Issue date:	11/10/1987
From:	Jerrica Johnson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20236Q480	List: IR 05000333/1987021 ML20236Q478 ML20236Q495
References
50-333-87-21, IEB-84-03, IEB-84-3, NUDOCS 8711200097
Download: ML20236Q501 (17)

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

. Report N Docket N License N DPR-59 l

Licensee: Power Authority of the State of New York l

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P.O. Box 41 Lycoming, New York 13093 Facility: J.A. FitzPatrick Nuclear Power Plant f Location: Scriba, New York _

Dates: September 1 - October 20, 1987 l J

Inspectors: A. J. Luptak, Senior Resident Inspector G. W. Meyer, Project Engineer  !

Approved by: h h 11 16} W 4.ft.Johnshj, Chief, Reactor Da'e t

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Pr6jects Section 2C, DRP q i

Inspection Summary:

q Areas Inspected:

Routine and reactive inspection during day and backshift hours of Licensee )

Event Report review, operational safety verification, surveillance 1 observations, maintenance observations, followup of plant trips and an l event, IE Bulletin followup and review of periodic and special report I This involved a total of 138 inspection hours which-included 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of backshift and 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> of weekend inspection coverage. Backshift inspection was conducted on September 30 and October 18, 1987. Weekend inspections were conducted on September 12, 13, 20, and October 17, 198 Results: <

During this period, two violations were identified. One violation involved the licensee's failure to perform written safety evaluations for changes made to the facility as described in the FSAR (section 9). The second violation involved the failure to follow a procedure for erecting scaffolding near safety related equipment (section 5.c). An Emergency Diesel Generator actuation occurred during transfer of house loads; this event is a repeat actuation which occurred on June 11, 1987. A more timely procedure change by the licensee following the previous event may have prevented this actuation (section 10). Areas of concerns were noted in the control of transient equipment in safety related areas and fastening of equipment covers (section 12).

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8711200097 871113 3 PDR ADOCK 0500 G

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j DETAILS

1. ' Summary of' Plant Activities lI-The inspection period began.with a plant startup being. performe .

i following alreactor scram 'of' August 28 due to a generator load' rejec <j-The piant operated near 23% power while monitoring the main'~ generato I and began to-increase power-on September 3 with the plant reaching full power.on September 6. .On September.7,.another reactor scram ]

.a occurred following'a turbine trip due to-a generator load reject; this {

scram was similar to the August'28 even The plant;was restarted'on i September 11 and returned to full ' power operation 'on, September 16 after completing detail _ed generator: testing. On September.-24,a reactor scram occurred, due to. low reactor vessel' level. caused by the~ ,

loss of the A reactor feed pump. A plant restart was conducted on September 25 and the plant operated near'62% power while  :{,

troubleshooting the A feed pump. The plant returned to full power- j

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. operation on October 11 and remained there-through the end of'the j

! inspection perio . Previous Inspection Findings (Closed) INSPECTOR FOLLOWUP ITEM (80-05-06): Proper'use of Instrument:

Calibration Reports (ICR). Since 1980, the licensee has generated: ..

many individual instrument surveillance and maintenance procedures and .(

therefore has significantly. reduced.the number'of.ICRs required. The forms are still used for the balance.of plant instruments. The inspector has verified that the forms for these instruments' had been 1 properly completed. This item is close (Closed) INSPECTOR FOLLOWUP ITEM (83-04-03): Licensee to ac't on BWR i l

owner's group recommendation regarding two stage' Target'. Rock, Safety Z

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Relief Valve (SRV) setpoint drift. Although the licensee'has ~

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continued to have some SRVs experiencing setpoint drift, the inspector

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has verified that the licensee is actively! pursuing the owners group "

l recommendations. Based on the licensee's actions in this area, the l inspector has determined this item no longer requires formal followup l but will continue to monitor the licensee actions in the generic resolution of SRV drift problems. This item is closed.

L (Closed)' INSPECTOR FOLLOWUP ITEM (84-BU-03): IE Bulletin 84-03, li Refueling Cavity Water Seal: As discussed in section 11 of this report, this item is close .

(Closed) INSPECTOR FOLLOWUP ITEM (86-10-02): Identification and testing / replacement of PK-2 test blocks in protective circuits. As the result of the failure of a test block in the protective relaying circuit, the licensee reviewed plant drawings and conducted plant walkdowns to identify if any other PK-2 ' test blocks were in use in the plant. No' additional PK-2 test blocks were found. 'TheLinspector also-I o

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. reviewed Work Request 71/52186 and modification 86-90 which removed or replaced the. existing PK-2 test blocks with a more reliable test b1cck. 'This item is close (Closed) UNRESOLVED ITEM (86-23-01)i Scaffolding ere'eted near safety-related equipment. The licensee has'_ implemented a program to control scaffolding utilizing Plant Standing Order (PS0) 51, Erection of' Scaffolds Near~ Safety Related, Equipmen This: procedure lprovided

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guidelines to assure ' scaffolding will not damage or impair safety-related. equipment during normal plant operations and postulated seismic events. Althot.gh a' failure'to follow PS0 51 is documentedLin this report, PS0 51. is considered adequate' guidance to properly l control' scaffolding. This item is clossd.

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(Closed)-UNRESOLVED ' ITEM (87-19-02) Setpoint change to Safety Relief Valve (SRV)' temperature recorder. The. inspector observed'and reviewed modification MI-87-114. This modification lowered the setpoint of.th SRV discharge temperature which will activate the. control room; annunciator indicating a lifting or leaking SR ~

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In' addition,.the 1 annunciator will-now be. received on a 25 degree F/ min rate of rise on any SRV discharge temperature. This . item is close . Licensee Event Report (LER) Review The inspector reviewed LERs to verify that:the details of the events were clearly. reported. .The; inspector determined that each report was adequate to assess the event, the cause. appeared accurate and was supported by details, corrective actions appeared appropriate to correct the cause, and generic applicability'to other' plants was not in questio . During this inspection period, the following LERs were reviewed:

I LER 87-04-01 is a supplemental LER reporting results of Main. Steam-Relief Valve out of tolerance and licensee corrective action LER 87-12 reported two reactor trips which resu'lted from turbine trips-caused by a generator field ground. (see.section_8).

LER 87-13 reported Reactor Core Isolation Cooling System isolation The isolations were caused by a high steam flow instrumentation -

spurious failure. Troubleshooting failed-to identify.a.cause and the transmitter and trip unit'were replaced. The units were. returned to:

the manufacturer'for failure analysi LER 87-14 reported the automatic starting of the Emergency' Diesel Generators due to a momentary degraded voltage condition. (see-section 10).

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LER 87-15 reported the High Pressure Coolant Injection System '

inoperable due to a Suppression Chamber Water Level Switch being outside of Technical Specification toleranc LER 87-16 reported a Reactor Core Isolation Cooling System isolation 'l during the performance of surveillance testing. This isolation j occurred due to a high steam flow and resulted from an operator's i failure to follow the test procedur The operator initially failed )

to reopen a valve during valve cyclin Following completion of the valve cycling portion of the procedure, the operator recognized the q valve was in the wrong position but (in opening the valve) caused a d rapid repressurization of the steam line resulting in the high steam !

flow isolation. Licensee' corrective actions included counselling of the operator and review of the event with all licensed personnel, j 4. Emergency Notification System Reports (ENS)

The inspector reviewed the following events which were reported to the 1 NRC via the Emergency Notification System as required by 10'CFR 50.7 j The review included a determination that the reporting requirements 1 were met, that appropriate corrective actions had been taken, and that j the event had been evaluated for possible generic implication The following reports were reviewed:

Event Date Subject September 5, 1987 An Engineered Safety Feature actuation (Reactor Core Isolation Cooling isolation)

occurred due to spurious high steam flow signa September 7, 1987 Reactor scram due to turbine trip on generator load reject. (see section 8). ,

September 12, 1987 An Engineered Safety Feature actuation (Emergency Diesel Generator start) occurred ]

due to a momentary degraded voltage condition I during a transfer of house loads.during a plant startu (see section 10).

September 16, 1987 The High Pressure Coolant Injection System was declared inoperable when the Suppression Chamber Water Level Switch was found out of ..l

. Technical Specification toleranc I September 16, 1987 An Engineered Safety Feature actuation (Reactor Core Isolation Cooling isolation) J occurred due to a momentary high steam flow condition caused by an operator erro ;

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September 24, 1987 Reactor scram due to low reactor vessel 1 leve (see section 9). .I September 28, 1987 Significant loss of offsite notification system due to six emergency sirens out of !

service caused by lightin i No discrepancies were note '

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5. Operational Safety Verification .!

i Control Room Observations '

. Daily the inspector verified selected plant parameters and j equipment availability to ensure compliance with Technical

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l Specifications limiting conditions for operation. Selected lit i l

annunciators were discussed with control room operators to verify :

that the reasons for them were understood and corrective action, i if required, was being taken. The inspector observed shift turnovers biweekly to ensure proper control room and shift manning. The inspector directly observed the operations listed below to ensure adherence to approved procedures:

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Routine power operation Plant startups on September 11 and September 25, 198 Plant trip on September 24, 198 Issuance of Radiation Work Permits and Work Request / Event / Deficiency form No violations were identifie Shift Logs and Operating Records Selected shift logs and operating records were reviewed to obtain information on plant problems and operations, detect changes and trends in performance, detect possible conflicts with Technical Specifications or regulatory requirements, determine that records are being maintained and reviewed as required, and assess the effectiveness of the communications provided by the log No violations were identified, Plant Tours During the inspection period, the inspector made observations and conducted tours of the plant. During the plant tours, the inspector conducted a visual inspection of. selected piping (between containment and the isolation valves)'for~ leakage or leakage paths. This included verification that manual valves

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were shut, capped and locked when required and that motor operated valves were not mechanically blocked. The inspector also checked' fire protection', housekeeping and cleanliness,

. radiation ~.' protection, and physical' security conditions to. ensur compliance with plant procedures and. regulatory requirement During a routine tour of the Emergency Diesel Generator (EDG) ,'

rooms on' September 30, 1987, the inspector found scaffolding erected around and above three of-the four EDGs. This scaffolding was erected to. afford access for inspection'.of the main exhaust duct pipe support as part of a pipe support inspection progra ,

The inspector determined the scaffolding failed to meet the licensee requirements of Plant S.tanding Order 51~, Erection of .

Scaffolds:Near Safety-related Equipment,' Revision 1, dated July 29, 1987, which requires that scaffolding exceeding seven feet in-height-be rigidly tied-off to existing structural steel in each horizontal direction. In. addition,'the' procedure requires scaffold planks be tied o'r provided with wood' stops against slippage. Neither of these requirements were met in'that no rigid tie-offs were in place for the scaffolds and numerous ,

planks were found which were not tied-off or had wood stop The scaffolds were constructed under one work' request (WR) -J 96/59954. Work was begun under this1WR on September 22,.1987.' 'A scaffold tag was attached to' scaffolding.over two of'the EDGs t]

, indicating the installation had been reviewed for acceptability ~ '1 l on September 25, 1987. However, the inspector was informad tha l a scaffold checklist used to check the scaffolding installation had not been completed since the installation was not completed 1 l on all the scaffolding. PSO 51 requires.an inspection'beJ  ;

performed for compliance with the standing order by completing

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-l the checklist which would then prompt a review by the'0perations l Department. The responsible supervisor then~shall apply the .

scaffold tag to the' scaffoldin '

Following notification of the resident inspector.'s findings, the 'i licensee immediately removed the scaffolding from the EDGs. 'The licensee has revised PS0 51 to; 1) require more.. timely erection l

of scaffolding, 2) minimize the time partially constructed- j i scaffolding is installed, 3) avoid placement of scaffolding near  !

l redundant trains of safety equipment,' and.4) requiring separate- l work requests for each scaffold'to be constructed in safety '

related areas. Although training'was held' following-the issuance d of the initial PS0 51, additional training is being conducted on d the revised procedure to emphasize the procedure -revision and - 1 importance of procedural compliance in this are ,!

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.Technica1' Specification 6.8(A): requires that. written procedure d and adaiinistrativeipolicies be implemented.that' meet or' exceed , ,i the. requirements'and recommendationsLof,section 5;"FacilityL .

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~ Administrative Policies and Procedures of: ANSI N18.7-1972". The '!

failure.to insta11L scaffolding in'accordance withLpSO 51 above -r ;

three"of the four EDGs is aLviolation'of Technica1' Specification-

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6;8(A).(333/87-21-01)

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' Tagout Verificatio d

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The inspector verifiedf that the following ' safety-related- <

j protective'tagout' records =(PTR's) were proper by'observin'g the'  :

positions of breakers, switches and/or' valves: ,

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PTR 871837'on Intermediate RangeiNeutron Monitoring j

Instrumentatio H

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DTR 871990:on A Station-Battery Ventilation Systemi j

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PTR 872024'on,B Control Rod Hydraulic. System.:

No violations were identifie j

! Emergency System Operability )

The inspector verified operability of the. following systems by--

, ensuring that each accessible. valve.in the primary flow path wa , d, I

in the correct position, by confirming that powerLsupplies-'and, breakers were properly aligned.for components-that must activate upon an initiation r.ignal .and by visual-inspection of the major a components which might prevent fulfillment of their functional 1 requirements:

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A Core Spray Syste .

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Emergency Service Water Syste '!

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B Battery Ventilation Syste No violations were identifie j

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6. Surveillance Observations L' The inspector observed portions of the. surveillance procedures listed below to verify that the . test instrumentation.was properly calibrated;

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approved procedures were'used,.the work was performed by qualified l personnel, limiting conditions for operations were met, and the system j was correctly restored following the testing:

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F-ST-20K, Control Rod Exercise / Venting, Revision3, dated August- l l 17, 1984, performed September 10 198 .! ,

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F-ST-23C, Jet Pump Operability Test for Two Loop Operation, Revision 8, dated October 22, 1986, performed. September 11, 198 F-ST.9D, Emergency Diesel Generator Inoperative Test / Loss of 115kv Reserve Power / Loss of Station Battery, Revision 10, dated ;

December 17, 1986, performed October 8., 198 !

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RAP-7.3.1, Average Power Range Monitor Calibration, Revision 9, dated April 22, 1987, performed September 30, 198 F-IMP-2.1, Recirculation Pump Differential' Pressure, Safety J Relief Valve Line Temperature and Vessel Seal Pressure Instrument _ _ .

Test / Calibration, Revision 15, dated June 8, 1987, performed October 9,.198 F-IMP-T21, Main Generator Field Ground Monitoring / Troubleshooting,:

Revision 0, dated September 11, 1987, performed September 12, 1987.

I Theinspector'aldowitnessedallaspectsofthefollowingsurveillance test to verify that the surveillance procedure conformed to specification requirements and had been properly approved, limiting conditions for operation for removing equipment from service were met, testing was performed by qualified personnel, test results met technical specification requirements, the surveillance test documentation was reviewed, and equipment was properly restored to

. service following the test:

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F-ST-10, Main Steam Isolation Valve, Main Steam Line Drain Valves and Reactor Water Sample Valves Logic Functional Test, Revision 17, dated April 16, 1987, performed October 1, 198 No violations were identifie j

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7. Maintenance Observations 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 j 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 1 were properly implemented, that ignition / fire prevention controls j were properly implemented, and that equipment was properly tested '

prior to returning it to service, During this inspection period, the following activities were observed:

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WR 13/58901, replace trip units in Reactor Core Isolation; 2 Cooling Syste WR 07/S9900,. troubleshoot'and repair C Int'ermediate Rang ,

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WR 34/56216, troubleshoot h'igh. vibration tripEof;A reactor feed pump.

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WR 94-58911, troubleshoot ground on main generato WR 02/59960, resetL alarmslon Safety Relief Valve Discharge temperature recorde '

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No violations were identifie ,

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8. Followup on plant Trip Due to Load Reject' <

At 10:37 p.m. on September 7, 1987, the reactor scrammed from full'

power due to a turbine trip on generator load' reject. This. scram was? 1 similar to the scram which occurred on August 28, 1987, discussed in .I Inspection Report 50-333/87-19. Following the scram'of August 28, the exact cause of the load rejection could not be positively' identified

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and the reactor restarted on August 31, with instrumentation installed to monitor the generato '

The inspector reviewed the process computer alarm printout, the )

post-trip log, various chart recorders,.and the completed data sheets j for procedure No. PS0 53, " Post Trip Evaluation". Based on these "

reviews, the inspector determined that the operator's. actions'during the event were proper and in accordance with approved procedures land the plant responded as designe Following the scram of August 28, the. licensee determined'the generator trip was caused by one of two protective relay circuits, R either an exciter current differential or gen'erator field groun Both circuits were found to be operating correctly -with the exception of the " target" of the field ground relay. This " target" provides d indication when the relay has operated and was found.to' be stickin i In addition, testing and inspection of'the generator excitation system 1 indicated no faults or obvious causes for the-tri .

The licensee installed strip chart monitoring of the two circuits.Tto' j detect any future abnormalities. After the plant restart on August '

31, the generator was monitored for several' days while: power was . ,

limited to 25% so that a turbine trip would not result in a reactor '

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tri Power was then raised when no trips occurred at _ low powe :

Monitoring continued, however the current.which would. trip ~the, relays was not known and the licensee was monitoring the traces for trends N

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i and positive indication if another trip occurre It was noted tha during this time, the current in the field ground circuit was somewhat erratic and very sensitive to changes in the generator excitation, j Following the scram of September 7, indication from both the. field ground relay target and the strip chart recording determined that the i generator trip was caused by a sensed generator field ground. Testing j following the trip indicated that an 18 ma current in the ground 1 Review of the strip

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detection circuit was required to trip its rela chart recording indicated the unit had been operating at about 14 ma-for an extended period and had shown a rising current about I hour prior to the scra )

Again, in-depth troubleshooting with General Electric Company-assistance, including high potential testing of the generator field, .I failed to indicate the cause.of the generator field ground. However, !

information was'then made available of a similar occurrence at another d facilit The information indicated that a cupric oxide layer was found on the teflon tubing which supplies cooling water to the  !

exciter's rectifier banks. During operation of the generator, this i layer causes a ground path in the generator but following shutdown of

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the generator, the ground path no longer exists. The teflon tubes were removed and found to contain this oxide layer. The tubes were cleaned with a weak acid and reassembled.

I A detailed test procedure was developed to monitor and test the generator under rotating conditions and during subsequent power operations. Also, the generator field ground relay was placed in the 1 alarm only condition such that a ground would not result in a  !

generator tri Discussions .with General Electric Company personnel indicate the majority of plants operate with this as an alarm only

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relay since a single ground on the generator field is not a major j concer Following the startup of the generator, testing failed to indicate any other cause of the generator ground. In addition, monitoring equipment indicated the current in the ground detection circuit was more stable and reached a maximum value of about 5 ma when the unit reached full power (as compared to the 14 ma prior to the last scram).

Based on these results, it was concluded that the cause of the generator trip occurred due to the oxide layer which formed on the teflon cooling tubes. Under certain electrical conditions, this layer becomes fully conductive and resulted in the generator field groun The licensee will include cleaning of the teflon tubes as a routine preventive maintenance activit No violations were identifie . _ _ _ _ _ _ _ _ _ _ _ _ _

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11 Followup on Plant Trip Due to Low Reactor Vessel Level At 7:38 a.m. on September 24, the reactor scrammed from full power due to low reactor vessel level. The low level occurred when the A reactor feed pump (RFP) tripped. As reactor water level decreased due to the feed pump trip, operator action was taken to reset the recirculation motor gerierator scoop tube speed controls which have been kept locked-up due to flow oscillations at high power. Resetting the scoop tubes allows the recirculation pumps to runback to 44%

speed, thereby reducing power within the capacity of one feedpum However, the approximate 8 second delay in recognizing and performing the evolution to permit the recirculation pumps to reduce reactor power allows water level to drop low enough to cause the scra The inspet. tor arrived in the control room within minutes following the scram ana observed the operator response to the the event. The inspector also reviewed the process computer alarm printout, the post trip log, various chart recorders and the completed data sheets for procedure No. PS0 53, " Post Trip Evaluation". Based on these observations and reviews, the inspector determined that the operator g actions were proper and in accordance with approved procedures, and that the plant responded as designe The cause of the trip of the A RFP was high vibration. This trip was set for 3.25 mils vibration. On September 25, a startup was conducted and the plant operated at about 60% power (which is within the capability of the B feed pump) while troubleshooting was performed to determine the cause of the high vibration of the A RFP. During the extensive troubleshooting efforts, several anomalies were found which most likely contributed to the high vibration. An imbalance in the turbine was found which results in approximately 2 mils of vibration while at normal full power operating speed. This imbalance is planned to be corrected during a two week maintenance outage scheduled for January 1988. In addition, the vibration detector was found not to operate freely and may have spiked causing the high vibration trip; the faulty detector was replaced. During the turbine inspection the high pressure turbine bearing was found to be slightly outside the technical manual tolerance and was replaced. The pump bearing was also replaced and the shaft realigned. Due to the higher vibration, the licensee decided (with vendor concurrence) to jumper the high vibration trip of the A RFP, to increase the alarm setpoint and provide detailed guidance to the operator for action on high pump vibratio The reactor feed pumps are described in section 10.8.3 of the plant's Final Safety Analysis Report which lists the pump trip signals that are provided, one of which is the high vibration trip. The decision to jumper the high vibration trip was discussed during a Plant Operation Review Committee (PORC) meeting on October 9, 198 During

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 -trip and' concluded that.no unreviewed' safety qu'estion exists as
 ' described in 10 CFR 50.59, 10 CFR 50.59.a.1 allows'the. licensee to make changes in^the.fability  )

as described in the safety analysis report without prior.. Commission- j approval unless the change involves an unreviewed safety questionL In 1 addition, 10 CFR.50.59.b.1 requires the licensee-to maintain' records- l of changes in the. facility including a written safety evaluation which j provides-the bases for the determination that the' changes..does.no 'I involve an unreviewed. safety question. . .Although"the. licensee reviewed the issue in'PORC, the' failure to perform.a written safety evaluation- j to' provide the bases for the determination of an unreviewed safety ,1 question is one example of a violation of 10'CFR 50.5 ,1 The. inspector.also found.that the licensee; failed..to perform.a written ) safety evaluation considering plant operation 'with the recirculation motor generator scoop tubes locked up. Operating in.this condition i

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prevents the automatic runback features of the recirculation speed l control syste The runback features of.the recirculation system are described.in the: 1 plant's FSAR section 14.5.5.3, " Loss of Feedwater Flow Transient ] Analysis". The FSAR states "An immediate runback in both -  ! recirculation loop speed to 44 percent of rated speed results.when any j individual feedwater pump falls below 20 percent of its rated value j and the reactor water level is below the low level alarm:setpoin ! The analysis shows that this runback occurs at about 3.5 seconds after 1 the feedwater pumps are tripped. Another interlock with-the Recirculation Flow Control System will further run back both speed  ! loops to about 20 percent speed".

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In addition, two recent plant scrams'have o'ccurred which may have been averted if the runback feature had not been locked up. In both cases,  : while operating at full power, one of the reactor feed _ pumps. trippe ! In both cases, the operator unlocked the scoop tubes about 8 seconds after loss of the feed pump; however, this slight del ~ay in the runback i resulted in larger level decreases which exceeded the low level scram j setpoin The failure.to perform a written safety evolution to provide the bases for the determination of an unreviewed safety question is a.second  ; example of violation of 10 CFR 50.59.'(333/87-21/02). '

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1 Followup on Emergency Diesel Actuation  ! On September 12, 1987, while conducting a plant startup following a plant trip on September 7, 1987, all four Emergency' Diesel Generators-(EDG) (both trains) started due to a momentary degraded voltage! condition on the 4160v emergency busses. As per plant startup procedure OP-65, after placing the main turbine generator on the grid, -

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1 operators were'in the process of transferring 4160v' house-loa'ds from the offsite 115kv power supply to the. main turbine generator outpu . This is the second occurrence of- the EDG_ actuatio.n on degraded grid voltage;'the first occurred during a plant startup on' June-11, 198 (see Inspection Report 87-12).

The transferring of house loads is accomplished on four. separate q electrical busses. The 10100-'and'10200. busses supply th .

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recirculation system motor generators.and are normally transferred l first. The 10300 and 10400 busses. supply the rest of the plant loads' ! including the safety-related emergency bussesL10500 and 1060 To perform the transfer, voltages.must be matched between the offsite .I power supply and the main, turbine: generator output. An adiustable load tap changer on the transformer from the main turbine generator:is- ] used to adjust this voltage t.o match with offsite voltage. Prior to : the beginning of,the. transfer, the voltage on'the 4160v busses was { approximately 3850v due to a'. lower-than-normal 115ky voltage. This t condition is not uncommon when the plant loads .are being supplied from the 115kv offsite power supply. . During the, transfer evolution a voltage drop occurs due to the addition of load onto the ou'.put of the main turbine generator. After the transfer, voltage is again matched - with the tap changer prior to subsequent transfers. However, with a ' larger' amount of load on the main turbine generator, the voltage drop become larger. When transferring the last.of the four busses, the voltage drop was observed to-reach the degraded voltage setting of 3780v, which is indicated by a' marking on the emergency bus voltage mete The operator immediately proceeded to adjusted the tap changer-to raise the bus voltage; however, the time it takes to perform.this ., adjustment' exceeded the time delay associated with the degraded ] voltage relay of 9 seconds and the EDGs started. Bus voltage was ' restored within the approximate 10 seconds that'the EDGs take to reach rated voltage. Restoration of. voltage resets the logic and prevents an automatic swap of power supplies which would trip the normal supply breakers to the safety-related busses and allow EDGs to supply the busse During this event, the electrical power distribution system functioned as designed and no anamolie's were discovered.- As discussed in Inspection Report 87-12 and the licensee LER.87-09, corrective actions from the first event of June 11, 1987, were; 1) .l increase the operator's awareness by providing additional training and i procedural improvements by September 15, 1987,'2) add an annunciator- I circuit to indicate degraded voltage protection initiation to be i completed about January 1988, and 3) reevaluate the degraded voltage .! setting and time delay to be incorporated if feasible in September 198 q Additional training had been performed to increase operator awareness- i

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prior to the September 12 EDG actuation, however, no procedure changes were made prior to this event. During a transfer of-house loads on

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I September.1,11987, two operators were used to transfer loads'..'One

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operator immediately increased voltage using'the tap changer following the breaker manipulation by'the other operator. This eliminates a several .second delay if both operations'were performed by' one

. operato Following the actuation on September 12, a temporary procedure change-was made on September 15 adding' cautions concerning.the. degraded; voltage conditions and requiring two operators to' perform. the transfer'. During a transfer of house loads on. September 24,.the busses were again' transferred without incident using two' operators ~.

Although .it is recognized that .the use:of:two operators is not'a fool proof or.long-term solution, it has:been successfu1Ein saving-time in restoring voltage during a transfer ~ . Although the licensee met their commitment following.the actuation 1of

' June 11, 1987,'of'the procedural change by. September' 15, 1987, theyL failed to take more timely action which may have prevented the-actuation which occurred on September 12, 198 The' licensee is expediting the review ~fo the degraded voltage protection system with'the results of the review expected by November 30, 1987. This item identified in Inspection Report 87-12 (87-12-03),.

will remain unresolved pending inspector review of' additional licensee action . Followup on IE Bulletins Bu11etin 84-03, Refueling Cavity Water Sea This Bulletin requested that the licensee evaluate the potential of a refueling' cavity water seal failure. The NYPA evaluation of seal failure was documented in Bulletin response letter JPN-84-85 dated December 20, 1984, and was updated in letter JPN-87-014 dated March 17, 1987, to revise'an error found in the previous letter regarding the as-built condition of seal leak detection systems. Generally, NYPA'has-concluded that the installed cavity seal is not susceptible to gross failure and though improbable, a gross seal failure is unlikely to. damage the fuel. .The inspector reviewed the response letters, the attached analyses, an the referenced design drawing The FitzPatrick refueling cavity is sealed between the reactor vessel and the reactor well wall by two refueling bellows and a refueling-bulkhead. The bellows'are made of stainless. steel, are' welded int . place, and contain no inflated or nonmetallic pa'rts. Based on this

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construction the seals are judged not to be susceptible.to gross' seal failure. . Also, the bellows are installed below'the level of the bulkhead and are protected by cover plates; therefore, damage due to l

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falling objects is highly unlikel . _ _ _ . -___.-__- _- -

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Though improbable, the consequences of seal failure were reviewed and found to be acceptable. Specifically,.when the reactor cavity is flooded, leakage from gross seal, failure could be replaced via the-systems designed to flood the core, such as the Core Spray System and the LPCI mode of the Residual Heat Removal System. The estimated maximum leakage rate of 7,100 gpm is well within the makeup capacit Further, disregarding the makeup flow, if a gross leak developed while the refueling pool gate was open and drained the pool, spent' fuel would be covered by a minimum of one foot of water. This water would provide sufficient cooling to prevent fuel damag Also,~the I analysis concluded that if fuel was being moved during the worst case j seal failure, it would take a minimum of 20 minutes before the level q drained down seven feet to uncover the fuel in' transit. This was q judged sufficient time for the operators to take. action (i .e. , lower i the fuel into place and initiate makeup flow). l A NYPA walkdown of the reactor well drains during the recent refueling outage found that the inner bellows leak detection flow switch had ] been installed on the wrong section of drain piping. Accordingly, the q later response letter noted this problem and. committed to correct.'this ' error by means of a modification during the next outage and to install -1

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a similar leak detection system for the outer bellow Based on the above review, Bulletin 84-03 is close I 12. Regional Administrator Tour On September 21, 1987, the Region I Administrator conducted a routine tour of the facility to observe housekeeping and material conditio The Regional Administrator concluded that the plant was generally well maintained and was considered above average for a plant of its ag One area of general weakness noted was the presence of and effect that transient equipment may have on safety related equipment. This included evidence of material falling from scaffolding, numerous pieces of equipment on wheels, and a gas bottle tied with rope to an !' instrument lin The licensee is reviewing this issue to determine actions which may be i required for correction on a programmatic basis. This item is i unresolved pending further review of the licensee's action (333/87-21-03).

The second general weakness was the lack of attentiveness to properly closing or securing cabinets and equipment covers. Some had evidence of stripped fasteners, missing screws, or fasteners not properly ) secured, i l l i

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i i The licensee plans to conduct walkdowns of equipment to identify and  ! correct inadequate closure of equipment. In addition, methods to i assure post work installation of covers or periodic review of equipment are being considered. This item is unresolved pending , further review of the licensee's actions. (333/87-21/04). l

i In addition, specific weaknesses in material conditions or . housekeeping were pointed out. These individual items were noted by, ' the licensee for corrective actio . Storage of Transient Equipment in Safety-related Areas

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The inspector reviewed the ' storage of transient equipment having the h potential to adversely affect safety-related equipment in accordance with Region I Temporary Instruction 87-03. No internal licensee response to Information Notice 80-21 with respect to transient J equipment could be~ locate The only formal procedural control for the storage of transient equipment at the facility addresses the { q erection of scaffolds near safety-related equipment, PS0 5 '

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implement PS0 51 was identified during this inspection period. In i addition, as discussed in section 12, several examples of transient i equipment and, specifically, equipment on wheels have been identified throughout safety-related areas. The licensee in the past has not ' considered the storage of this equipment as a hazard to other equipment. As discussed above, the licensee is reviewing this issue to determine what corrective action is required including future programmatic improvement . Environment Qualifications of Suppression Chamber Water Level Switches

' W ng t." performance of routine surveillance testing of Suppression thamber Water Level Switch 23-LS-91B, the switch setpoint was found to exceed Technical Specification requirements. Corrective action required disassembly of the level switc The level switch functions with an identical switch in a one-out-of-two logic to provide an automatic switch of the High Pressure Coolant Injection suction to the Suppression Chamber if water level in the chamber is 6 inches above norma During reassembly of the level switch, the switch cover was found to be missing an 0-ring which seals the unit. These level switches are considered to be environmentally qualified. Following 0-ring replacement on the B level switch, the A level switch was disassembled and also found to be missing the 0-ring. The inspector verified no other level switches of this type were in use in an application requiring environmental qualificatio !

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The licensee review has concluded that these level switches are not required to be qualified for a steam environment based on accident analysis conditions. This item is unresolved and will be reviewed in a followup inspection (333/87-21-05).

1 Review of Periodic and Special~ Reports Upon receipt, the inspector reviewed periodic and special report The review included the following: inclusion of information required by the NRC; test results and/or supporting information consistent with design predictions and performance specifications; planned corrective j action for resolution of problems, and deportability and validity of ___ report informatio The following periodic reports were reviewed: .

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August 1987 Operating Status Report, dated September 8,1987.

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l No unacceptable conditions were note . Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss inspection' scope and findings. In addition, at the end of the period, the inspector i met with licensee representatives and summarized the scope and l findings of the inspection as they are described in this repor j i Based on the NRC Region I review of this report and discussions held  ! with NYPA representatives during the e<it meeting, it was determined l that this report does not contain information subject to 10 CFR 2.790 i restriction ! l I

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