IR 05000412/1987060

Insp Rept 50-412/87-60 on 870829-1009.No Violations Noted. Major Areas Inspected:Licensee Actions on Previous Findings, Site Activities,Startup Test Program Implementation & Pressurizer Pressure Transmitter Inoperability

ML20236J374
Person / Time
Site:	Beaver Valley
Issue date:	10/29/1987
From:	Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20236J362	List: IR 05000412/1987060 ML20236J360
References
RTR-NUREG-0737, RTR-NUREG-737, TASK-2.F.2, TASK-TM 50-412-87-60, NUDOCS 8711060026
Download: ML20236J374 (15)

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U. S. NUCLEAR REGULATORY COMMISSION ,

I REGION I j Report No.: 50-412/87-60 '

Docket No.: 50-412 i i

License No.: NPF-73 Licensee: Ouquesne Light Company i Nuclear Group .j P. O. Box 4 1 Shippingport, PA 15077  !

l Facility Name: Beaver Valley Power Station, Unit 2

Dates: August 29 - October 9, 198 {

Inspectors: J. E. Beall, Senior Resident Inspector-S..M. Pin ale, Resident Inspector i Approved By: . ., M Lv. E. Triptf, Chief, Reactor Projects

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.Section 3A,-Projects Branch No. 3, DRP Inspection Summary: Inspection No. 50-412/87-60 on August 29 - October 9, 1987 geasInspected: Routine inspections by the resident- inspectors (209 hours0.00242 days <br />0.0581 hours <br />3.455688e-4 weeks <br />7.95245e-5 months <br />)

of licensee actions on previous findings, site activities, startup test program implementation, pressurizer pressure transmitter inoperability, reactor vessel level indication system anomalies, NUREG-0737 followup, diesel generator instrument vibration, and LER revie !

Results: During the inspection period, ' the licensee completed power ascension testing through the 75% power plateau. Major test milestones included conduct of the main steam isolation valve closure'at power test and the loss of offsite j power tes One unresolved item was identified concerning NUREG-0737 Item II.F.2, " Inadequate Core Cooling Instrumentation" (Detail 8). There were no violations. The failure of licensed operators to adequately followup the fail- .

ure of an auxiliary feedwater pump (AFP) to start following a valid start signal is discussed in Detail Fortuitously, this inoperable AFP was again identified later in the same day during a surveillance test before the tim l i

limit was exceeded in the associated Technical Specifications Limiting Condi- '

tion for Operations action statemen I i

8711060026 DR 871101 ADOCK 05000412 ]

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t 1-DETAILS ' Persons Contacted

.During-'.the re' port period, interviews and discussio'ns were conducted wiIh?

members of the' 1icensee's . management . a'nd staff as necessary . to.' support:

inspection activitie . Project Status Summary

'During the inspection period, the. licensee. continued power ascensionitest--

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ing. 'and completed most testing up to the<75% power: plateau. .Ma'jor test:

l milestones accomplished include the . loss 'of L offsite power .-test and f the l- main -steam isolation valve closure test; .beth tests were initiated atL30%'

i power .on . September 9,- 1987. 'At .the end of. the inspection period,4 :the'

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licensee was beginning to increase-power to'90%. ~'

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Scheduled dates for the remaining , power ascension tests ands other major

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milestones are listed below- ..

Achieve 100% Power October 13,l1987 Load Rejection from 100% Power: October 18,.1987 Turbine Trip.from 100% Power' October 19,.1987- '

Commercial Operation  : October 23,'1987

' Inspection Program Status S'ummary Preoperational test ' program inspection ,is essentially complete withs only -

the review of the results of 'certain' tests and r' etests remaining. Inspec .-

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]1 tion of the licensee's ;startup 'and power ascension program;. continued as? -J documented in Inspection Reports 50-412/87-59', 62cand 63.' The' current" ,

d status of the startup inspection pr.ogram isLas follows:- l'

% INSPECTION. COMPLETE .

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AREA END OF THIS PERIOD- -END OF LAST PERIOD = 1 a

_-q Overal1 Program 80 ,- 60- .i

Procedure Reviews: 95 1 90'

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Test Witness: 80 - 60 Results Review: .75 - 40

r The current- inspection status - is consistent with ; the' applicani's startupD program ' progress. At the; end : of this inspection'. ' period, there swere i ,

approximately 20 open NRC:inspecticn items as listed below; i 3:

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i-NO.-dF'0PENINSPECTIONITEMS

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. TYPE OF= ITEM: 'END:0F THIS' PERIO END ~0F TLAST' PERIOD '

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Violations '2 l' * >I Deviations >

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Construction Deficiency  !

Reports 0 ;0; j i

Unresolved 16- , 17- <

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TOTAL 20 20L . - Licensee Actions on Previous Inspection Findings ~ d M

4.1 (Closed) Unresolved Item-(86-19-01): Main Steam Safety' Val.ve (MSSV) ~ .i

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Ring Settings. The : inspector reviewed- the licensee's- corrective:.

actions' regarding MSSV ring settings. This7 tem 1 was:l opened'.ino ,

Inspection Report (50-334/86-19) and followed_uprin' Inspection' Report )

50-334/86-33. The inspector determined.thatJthe.1icensee..is.a member? '

of the Westinghouse Owners Group (WOG) . involved in a testing: program to determine proper ring settings in' response toL NRC -IELInformation-L Notice 86-05 regarding the problem ofc improper 1 ring' settingsi lThe

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test program involves steam Jtesting . att the Crosby test facility' to d; determine generic ring settings forLvalves!. that < are . similar.-; to the 3 plant installed MSSVs.

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The inspector reviewed the-details'oftn Crosby? Test Report?4388 ofL l

, June 18, 1987, for the completed Phase 1- Generic Ring Setting 1 Test'

l Program that involved Crosby 16210 HA: safety:: valves (similar to i the

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BV-2 valves). The report recommendations were.to set Lthe nozzle ring ' d at -100 notches and the . guide ring 'at :-50.: notches when a . maximum i blowdown of 11.6% can be tolerate 'l

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In response to the testing data, the licensee requested Westinghouse j to perform a safety evaluation l to. examine the acceptability ' of) the l

11.6% blowdow Westinghouse . examined the

FSAR Raccident analyses, j

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except for the st'eam generator- tube < failure '(SGTR) analysis,, and con- 1 l cluded that the 11.6% blowdown would t not; result' in;. exceeding 1.any o q i

l design or' regul'atory limit. Regarding the SGTR evaluation, Stone and:- r -!

Webster Engineering Corporation; reascessed:the potentialiradiological- l consequences of: the change in mass -releases and : prepared l ai. safety; i evaluation and submitted a FSAR proposed. change' to radiation? do'se . j rates for the SGTR event.LThe licensee has also adopted the':1977=ASMER l code edition throug'n Summer,1979, addenda' and .has' revised the ?MSSV 4

- valve specification l2BV5-225 to conform to~.the new reseati.ng pressur '

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The licensee has modified the MSSV ringzsettingsito.thos'elrecommended in the Crosby test report HThe licensee also~ made appropriate; reviews: ,

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.of theother related details involved with the1 change"(FSARf accident'

7 ' analyses and ASME ' code). This item -is iclosed.~ ^ The,'generi.c caspects -

L 'of .11.6% blowdown and the' safety evaluations related to thejring set-ting change.will be reviewed by-NR .2 (Closed) NRC Contractor Identified 1 Technical Sper.ificationslDiscrep-- I-ancies. In'spection . Report 50-412/87-34 Jdocumented the -onsite' review

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performed by = a ] team , of ' NRC contract s personnel 1which 1 compared ! thei .

proposed Technical . Specifications- (TS) to L the' FSAR, the SER, : draft" 'l procedures and . installed hardware. . The inspection . identified .manyi >

inconsistencies in the documents which were. minor in nature and!whic q were due to changes in .setpoints as well as thes draft nature of; the :

site procedures and the : proposed. TS.. No Significant; hardwarerdefic--

iencies or safety' concerns were identified.' SER' Supplement 6 correc-! '

ted .several of the items 'and' the ulicensee's continued o procedure development corrected others. The licensee'.' documented ; many of L the ,

corrective. actions in letters'. dated' JulyE 15, 1987, . and August :10, '

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1987. The -inspector reviewed- the revised procedures and theiissued j TS and no deficiencies were identified. This item is closed i Site Activities R

Throughout the inspection period, the' inspectors toured ; the : licensee facilities. General work activities were observed including construction,.

surveillance, testing and maintenance. TheLinspectors also nonitored the ,

licensee's ' housekeeping, security and preliminary radiation control;activ-In particular, ' the - inspectors monitored .the licensee's ' progress

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itie towards achieving full' power and' commercial operation.' .

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-i 5.1 Reactor Trip During Power Ascension Testing! '

On September 9,1987, a reactor trip ' occurred?from 30% power due -to

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low-low water level on the '!A" steam. generator during the. main' steam  ?

isolation valves (MSIV) closure Eat power test ((IST 2.21A.02); Upon  :

closure of the MSIVs, steam ' generator water levelst shrunk" rapidly, i and the reactor tripped approximately 10 seconds into:the transient <

The feedwater regulating valves. were.~ operating in ' automatic. .Th trip was not entirely unexpected ! cut ~ wa's not ' part ofethe jreplannsd NRC inspectors were present in the ~ control . room and : observe '

tes the test and ' the trip response. L0perator actions were prompt -and- q

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correc Emergency Operating Procedures were L used .to. stabilizerthe?

plant 'in Mode Control. room Supervision was in? clear! control- '

managing the actions of the operators. The-interface betweenLtesting" n and operations personnel was excellent' and allowed timely lMSIV re-:-

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opening for steam dump operation (vice SG ' relief; valves); Thei NRCK d was notified 1 of ~ the' plant trip per 10:CFR 50.72 ' reporting require-- q ments. No deficiencies were observed during ' conduct iof ^the stes g i

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5.2 Reactor Trip Due to Feedwater Regulating Valve Failure On September 28, 1987, - a reactor and turbine trip occurred from

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j approximately 75% power .due to low . steam generator. (SG)' water level '

coincident with steam flow / feed flow (SF/FF) mismatch on the "A" SG, 3 Prior to the' event, na September 27, the "A" SG 1evel transmitter 1 drifted down scale and was declared out of service, and the' associated j bistables were ' tripped per plant Technical Specification require- '

i ment Late on Septerhov 27, plantLoperators noted erratic operation of the Feedwater Regulating Valves (FRVs) in that the valves were moving excessively to conten1 SG levels while in automati Therefore, the "B" and "C" FRVs, were placed"in manual . ~ The licensee

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suspected that the FRV1 control problems were. due to plant operation at about 73% power with only one main feedwater pump (MFP) in 'ser- l vice; a MFP run-out test was in progress at the time. On September '

28, when the test was completed, plant operators were permitted to start the second MFP. When the plant was stabilized, the "B" FRV was 1 placed in automatic to see if the valve would demonstrate proper per- 1 formance while two MFPs were in operation. As soon as the valve was f '

l ' switched to automatic, it failed to the full open positio The l resulting secondary plant transient caused feedwater flow swings in i the "A" SG, whose FRV was operating in automatic. The "B" FRV was a l subsequently returned to, manual, however, the "A" FRV was apparently l l

still responding to changing SG 1evels. A SF/FF' mismatch condition l

! subsequently occurred on the "A" SG. This signal', along with the l signal that resulted from the tripped level bistables on that same j SG, generated the reactor trip signa The trip occurred at 1:56 am ]

on September 2 Prior to' the plant trip, the recirculation lines 1 for both MFPs were isolated due t'o the ongoing run-out test. 'There- J fore, both MFPs were manually shutdown immediately following the '

plant trip for pump protection concerns. This action caused an auto- i natic initiation of the auxiliary feedwater (AFW) system. The licen- i see reported the above pursuant to the requirements of 10 CFR 50.7 i Licensee investigation into the FRV failure identified a bad circui card in the "B" FRV controller which was subsequently replaced. The plant reached criticality and Mode 1 operations on September 30. The ;

licensee planned to continue to monitor and evaluate the control i functions of the SG level control systems during subsequent plant 1 operation .3 Reactor Trip and Safety Injection Due to Low _Steamline Pressure On September 29,1987, at 2:19 am, a reactor trip and safety injec-tion (SI) occurred from 15% reactor power due to low steamline pressure. During a turbine startup evolution, a turbine overspee protection controller (OPC) test 'was being performed. Due to an apparent inadequate procedure regarding OPC test conditions, the turbine governor valves began to open rapidly, resulting in a large,- q

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s .g < 1 sudden ~ drop in main Lsteamline- pressure resultinglin the reactor trip - ,

and safety-injection. An Unusual EJent wasideclared and reported 'at 1 2:35 am- per Station . Procedures due -td 'the automatic ' initiation- of:the q'

SI . system from a valid signal. Approximately 2,000 . gallons of. bor ated : water was injected -into '. the - core ' from ; the . SI syste System -

restoration and recovery was' completed by 2:30 am. iThe_ Unusual' Event

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R wa's terminated . at 2146 ' am. The ' reporting requirements; of '10ECFR -

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During the evolution and while atM1800 rpm, ?a key switch was pla' e c .-

v1; in the . test position', which fully closed the- governorfvalves to te' stL 'H the OPC. The switch was left in test for about '1-1/4 minutest which1 J allowed the turbine spe'ed toidecrease. When the switch was returned 1 to normal, .a large l mismatch signal (150 rpm)- was generated ;between actual speed and the program speed lof- .1800; rpm. The ?large mismatch:. , d;l signal caused the governory valvesito open, rapidly',f which decreased; 1 steam pressure to the ;10w steamline. pressure Ltrip setpoint -and which ^

initiated the. reactor trip and S ,

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The' OPC test . procedure or.iginallyJ performed this test' at; 550.' rpm,c .g however, several low EHC pressure turbineitrips occurred during1per-

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j formance of the test. FTherefore,'the licensee requested supportL from: ]

the main turbine / generator vendor (Westinghouse) Lto change _ the: test: 1 so that additional- inadvertent turbine trips; woul.d; bef avoided. iThe- d licensee subsequently- changed , the procedure i based c upon tinf6rmation:

provided - to. themi in the Westinghouse ! Instruction ' Manual. However,

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the manual provided insufficient and inadequate information :such that ,y

]d important steps. and/or precautions . were :'omitted Lin. : the :-procedur j q

Westinghouse ' subsequently-issuedL a letter to the; licensee documenting '

the correct steps that 'would be required'.tol properly 1 perform the10PC : 1 test. Westinghouse also' revised their Instruction. Manual to reflect ' s H the necessary changes. The licensee used6the1new . Westinghouse recom- H mendations to generate' an Operating Manual. Change Notice for.'the'af - j fected procedure to reflect the n_ecessary changes;. The ~ne'w? pr' ocedurez 1 has_ not yet been used at the. station! The resident 7 inspectors will: )

monitor subsequent OPC testing activites to verify theieffectiveness ,

of the Westinghouse recommendations,

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5.4 Reactor Trip Due to Feedwater Transient l

On October 8, the plant: automatically tripped from' 55% power due :to1 low water level on the "A" -. steam generator..(SG) coincident with a' H steam flow / feed flow (SF/FF) - ' mismatch signal . ; A s feedwateri system ~ j transient was initiated when s plant?operatorsJplaced a ?secondo feed : '

R water pump in service ,. in preparation for " swapping L feedwater : pump , O t  :

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When the second pump was placed in service, the feedwater recircula-

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tion valves opened due.to the increased feed capacity with two.run-ning feedwater pumps. . Additionally, the feedwater regulating valve ,

(FRVs) began to respond erratically. The feedwater control system j (FCS) was operating in automatic for all three FRVs. The transient ,

caused an SF/FF mismatch signal to 'be generated. A . SG low water '

level on the A SG ("A") was already in. a tripped condition due' to a i transmitter problem identified on October 7.- These two . signals I together caused the reactor trip. Plant specific Emergency' Operating Procedures were followed and the plant'was stabilized in Mode 3 fol-lowing the trip. The' licensee made the required notifications. per 10 CFR 50.72 reporting requirement _ _

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This event was the second reactor trip that occurred during thi l inspection in which an SF/FF mismatch signal was ~ generated while a-

, low level bistable was already in a tripped condition.'(See Detail j

! 5.2). The licensee stated that further adjustments.- to the F.CS are j l necessary, however, since many variables are involved and plant' -j l

sta'.us/ conditions have been variable per the startup program, the FCS '

has not been adjusted to optimum operating conditions. : The licensee -

" is continuing to monitor FCS performance and make: adjustments , as - 4

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necessary to stabilize the system. Also, the. inspectors questioned ;

l why a feedwater transient (swapping - feedwater . pumps) was performed- '

whi;e in a degraded mode (low level transmitters out of service).

The iicensee stated that the bistables are kept out of ' service fo'r minimal time periods and in accordance with plant Technical Specif1-cations. The licensee further stated that these' types of evolutions l are routinely performed throughout the industry without' incident, and final instrumentation and control cnd' mechanical adjustments -are j

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needed to provide added protection against similar occurrences.: The l licensee plans to continue troubleshooting and adjusting, as neces-sary, the FRVs and the FCS. The resident inspect' ors will monitor'the effectiveness of these licensee action .5 Auxiliary Feedwater Automatic Initiation l On September 10, during restoration from the loss 'of Offsite Power, !

(LOOP) test, the trip of a MFP initiated an AFW auto start signa The turbine-driven AFW pump was already providing. adequate flow and:

the operator was attempting to restore main feed. One electric AFV pump started but the other one failed to star The electric AFW pumps were returned to auto but, due to a cognitive error by shift'

supervision, the actuation was not reporte' .ior. the failure to sthrt investigated. The oversight was discovered within a few hours during a routine surveillance tes The actuation was reported and the hardware deficiency was corrected. Licensee investigation 'was.still ongoing at the end of the assessment period. Inspector review - and discussions with the operators indicate that this event was an iso-lated example of licensed operator erro ,

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5.6 Emergency Diesel Generator Automatic Start

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On September 21, the "A" emergency . diesel generator -(EDG) automati-'-

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cally: started due.~~to the loss -of power to its associated emergency j shutdown bus. During an attempt to start."A" charging pump, an' over -

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-i current condition occurred on the emergency shutdown bus resulting in- ,

the automatic opening of the normal power ~ supply breaker to the l emergency shutdown bu After the power supply was lost to ' the emergency bus, the EDG received an automatic start signal but did not ]

re-energize the bus due to the overcurrent conditions indication signal. Operators were 'immediately dispatched to reset the affecte relay phases, and were then able to restore normal _ power supply j secure the EDG. All Train B system components remained ' operable j

! throughout this even The affected overcurrent relay was subse- {

quently replaced and satisfactorily tested. The licensee's_.investi.-

gation into this event concluded that the cause of the overcurrent i relay failure was due to random component failur No further l similar problems occurred, j

5.7 Auxiliary Feedwater Automatic Initiation ]

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l On September 3D, while operating at about 30% power, an automatic- I i

auxiliary feedwater (AFW)-initiation occurred. A licensee contracted

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maintenance worker accidentally broke a control air line which cause l;'

a recirculation valve in the condensate system to . fail fully ' ope As a result, suction pressure to the operating main feedwater, pump -

decreased and caused the pump to automatically trip duef 'to low suc-tion pressure. The loss of main feedwater' caused an automatic start of both motor driven AFW pumps as per system design. Plant ~ operators were subsequently able to' start the other main feedwater pump, iso-late the recirculation valve and stabilize the, plant before a more j significant plant transient was : initiated. The recirculation valve control air line was subsequently repaired and ' the valve returned to service. The NRC was notified of this event.via' ENS'per 1.0 CFR 50.72 !

reporting requirements. Also worthy of _ note, is that nearby workers reported the air line break promptly, even before the transient _was complet Exact knowledge of the initiating event , greatly facili-tated operator respons With the exception of the issues discussed above, the inspectors had no  !

further concerns regarding these ' events or the licensee's followup /

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4 6. Pressurizer Pressure Transmitter Inoperability On September 15, while in Mode 5 (Cold Shutdown), the licensee discovered that all three pressurizer pressure transmitters were inoperable due to .

zero shifts of the instruments. On July 22, 1987, when .the plant was operating in Mode 3 (Hot Standby), maintenance work requests were initi-ated after plant operators noted that both pressurizer pressure control channels indicated about 50 psig higher than the three pressurizer press-

-ure protection channel The licensee investigated both the~ control and )

protection channels by checking the calibrations of the rack instruments- j tion; no problems were found. Recently completed transmitter calibration j procedures were also examined for potential commo'n mode failures (same test equipment, . same Iersonnel); no common cause was identified. The licensee concluded that since all calibration sheets and back up instru-mentation was verified to be in order, the non-class .1E, non-safety-related control transmitters must have drifted high. The licensee subse-quently decided to recalibrates all pressurizer pressure transmitters dur-ing the upcoming maintenance outage to verify their conclusions.

l During the outage, the licensee determined that all three transmitters in

the protection channels had experienced a zere- shift. The as-found data showed that pressure transmitter Nos. PT455, PT456, and PT457 read 37.4,

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34.4 and 46.6 psig respectively Consequently, pressurizer pressure would .

l have been required to exceed the high pressurizer pressure. trip setpoint by the amounts shown above before a trip to~ the channel would have

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During the licensee's mini-outage, all three pressurizer pressure protec-tion channel transmitters were recalibrates after they were allowed to l soak at operati1g pressures for approximately one day. Following the I

restart from the outage, licensee personnel entered containment to verify that the transmitters were still within specificatio A Heise gauge was  ;

placed on one of the transmitters and found to be withi,n 2 psig of the- ]

calibration value. The licensee plans additional corrective actions  ;

including specialized calibration for the instrument These corrective j

actions will be reviewed during subsequent routine inspections, j l i The zero shift phenomenon was previously ident.ified and reported (in l l accordance with 10 CFR Part 21 requirements) by the . instrument vendor )

l (ITT-Barton). The report was made on June 30, 1983,- and identified a .j i

potential defect in supressed zero Model 763 static pressure transmitters, i In response to the-Part 21 Report, the licensee's NSSS vendor (Westing- j house) issued a Technical Bulletin (No._ NSID TB-85-11) concerning the zero j shif t of Barton 763 pressure transmitter The bulletin explained: that'. j the supplier determined that the-.most significant contributors to ~ this i

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phenomenon is stress, imposed on the Bourdon tube;when the transmitter is I continuously operated at pressures near the sximum process inpu Westinghouse ' established a conservative drift estimate that would be expected over the duraticn of a fuel cycle, which was used to verify that actuations on high pressurizer pressure would occur without delays exceed-ing Technical Specification margin requirements (-34 psig). In this case,

.however, the maximum drif t experienced by the licensee was -46.6 psi j ;

The high pressurizer pressure reactor trip function is ~ credited in the loss 'of load / turbine trip analysis for BV-2. The current safety analysis as documented in the FSAR is 2425 psig. The safety analysis limit of 2425 psig would not have been exceeded using the zero shift values found on September 15, 1987 The licensee reported this event as required by 10 CFR 50.72 as operation i prohibited by plant technical specifications. The inspector questioned j

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the licensee as to whether a 10 CFR Part . 21~ Report was issued. The licensee stated that the required information would be . included -as part )

of the licensee event report (LER). The licensee discussed this with NRC '

Licensing, who stated that the inclusion of the Part 21 information in~the

.LER would be appropriate in this case because previous Part 21 Reports

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have been submitted. The new information would be used to update existing j databases and issue NRC correspondence, i f app-opriate. The inspector  !

will review the LER when it is issue l

,No violations were-identifie !

7. Reactor Vessel Level Indication System Anomalies

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On Septemoer 28, 1987, during a routine control room walkthrough, the' i inspector noted that the reactor vessel level indication ' system (RVLIS)

was apparently not functioning properly; two discrete' decreases in reactor vessel level appeared on the two hour level trend for a total of about 45  ;

minutes. The control room operators and supervisors 'were questioned, '

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however, none knew of any related. Work or system . related problems that would explain the level changes. The plant was in Mode .1 at the tim Technical Specification (TS) 3.3.3.8 (Accident Monitoring Instrumentation)

requires that two channels of RVLIS be operable while in Modes 1 thru l Action statements are provided to allow either one or both channels to be ,

cut of service for specified time intervals or, if not returned ' to ser-vice, a plant shutdown is required to be initiated.. Additionally, there is an action statement (applicable only for the first fuel' cycle) 'that allows the RVLIS channel (s) to be out of service longer -than the other applicable action statement requirement. .In that case, a special report is required to be provided to the NRC containing information . regarding action taken, cause of inoperability and plans scheduled for restering the channel (s) to an operable < status.

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The licensee subsequently < determined :that level f changes :, on6 the ;RVLIS

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dynamic head two; hour trend . graph coincided with work being Ddone..by the -

computer . integration groupi(CIG) and ., contractor 1 personnel-. . The E licen see'. =4 also determined : that. both RVL'IS 7 train's . were not : taken : .outL o_f i service simultaneously. 'The inspector expressed .a' concern regarding plant person >

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L nel placing .TS required : equipment out1of ; service without informing 1 the f g

,, operations staff. . The, licensee stated that this1 concern -is junique1 to cf v RVLIS, since, .by the caveat provided in TS; the system;is permitted to;be

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out. of' service-;for extended time periods'. The? licensee' identified? an apparent Leommunication problem and issued a; memorandum 1~to;allf CIGyper-J '

-j sonnel re-emphasizing' the station'.s' policy regarding: informing'and obtain-: ,

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ing concurrence'from the Nuclear Shift Supervisor.for the systems;that are to be~workea on or removed from1 service, o

I' During the licensee's investigationfinto' this event,' ith was11dantified /

that-the redundant sensor. algorithm ~(RSA) does .'not markivalues- from. an 4

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off-line train as bad. Consequently, since the' associated values efrom an ' '

off-line train .are not flagged as bad quality,1they' are used in:the calcu-lation to produce the trend graph,lwhich; resultsiin' a' bads display; This'

problem does not af fect . the . operability of L the" dynamic: RVLIS :(used Ewhen- 4 any combination of reactor coolant pumps are operating). iA Field Devia-

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tion Report has been.. generated to resolve the ~above Eissue. Additionally .

the licensee plans to" track the progress? of; the:: investigation and to '

obtain additional engineering inpu j Also identified during the licenseef s' investigation intoit'his event',!was that one upper range static head" channel . used for:leve1 Measurement Withf f no reactor coolant. pumps operating was . inoperable. : Maintenance . Work' d Requests have been initiated to repair : the;affected. channel. For : the1 interim, the licensee is preparing a specialf . report 1(to: bei submitted ' to" O j

u l the NRC) per . TS 3.3.3.8. requirements swhich will- provideE.information l

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regarding action taken, cause of the inoperabilityland plans?and schedule lj for restoring the chann'els to an operable statu '

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For further discussion on ' RVLIS, and NRCs tracking of the above' issue,'see~ W Detail '

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1 Item II.F.2, Inadequate Core Cooling' Instrumentation-  ;

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NUREG-0737 Item No. II.F.2 clarified the req'uirements 'for inadequate core q cooling instrumentation (ICCI) that was to be. installediand op'erating; '

prior. to initial fuel loa The Beaver : Val. ley, . Unit 2 Safety l Evaluation Report (SER) documented that this item.was an open issueLpending submittal > .i of . additional information'. The' licensee. submittedf addition'al:information j letters on April 11, 1986 and July 31, 1986. Supplemental.SERL(SSER) N g 2 confirmed a licensee commitment that-the -ICCI- system would beyinstalle and tested prior to initial: fuel load and-calibrated priorJtoireaching;50

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powe The NRC position was that . the system was required to be fully operational with appropriate Emergency Operating Procedures (EOPs) in place prior to initial fuel load. The acceptability of the final design was to be demonstrated by the successful completion of testing of the ICCI subsystems, l'ne licensee was further requested to provide an implementa-tion letter report so that the staff's review of this item could be com-pleted. As documented in SSER 2, Confirmatory Issue 50 was opened to track the above action On the basis of its review of FSAR Sections 4.4.6.5 and 7.5 and the addi-tional information provided by the licensee, the staff concluded that the design of the BV-2 ICCI system was -in conformance with the guidance pro.-

vided in NUREG-0737 and was therefore, acceptable. The licenses subse-s quently submitted an implementation letter report on May 12, 1987, docu-menting ICCI system completion and Confirmatory Issue 50 was closed in SSER No. 5. The inspector performed on-site inspections to vert ry imple-mentation of several of the licensee commitments, including a review of the installed system, its functions and capabilities, and the working level knowledge of the system maintained by plant operator " The ICCI system installed at Beaver Valley, Unit 2, include', (1) Core Exit Thermocouple (CET) Monitoring, (2) Core Subcooling Margin Monitoring, and (3) a Reactor Vessel cevel Indication System (RVLIS). Thri ICCI system is incorporated as part of the Plant Safety Monitoring Systen (PSMS).

The inspector verified that the system functional tests and calibrations were successfully completed prior to reaching 5% power per previous licen-see commitments. Noted test defletencies were documented for resolution and are being tacked by the licensee's internal tracking system. Plant specific Emergency Operating Procedures were verified to be in place per licensee commitment Technical Specification (TS) surveillance proced-

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ures were also verified to be complete and performed in accordance with TS requirement The inspector reviewed the training material and interviewed licensee training staff personnel and piant operators. Plant operators generally demonstrated an acceptable knowledge level of the system although some of the specific system messages were not fully understood. For example, data points are identified as either good, poor, mismatch or bad. Plant opera-tors were not aware of the differences in the messages, or whether the data was accurate information. Additionally, messages are provided con-cerning the data quality are received from the Database Processing Units (DPUs). It was unclear whether the operators could dif ferentiate among the various DPU status messages (ok, no, fault). While cognizant tech-nicians were familiar with the above mentioned messages, the operators did not possess similar knowledge levels on the status messages. Additional cperator training is needed in this are i

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i The BV-2 full power license . (issued on August. 14,- 1987) incorporates a j license condition (2.C.7 - PSMS) that requires ,the licensee to develop-a

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j verification and validation (V & V) plan which.will demonstrate the reli- -'

ability of -the - PSMS software. The plan is to be submitted to NRC on or -

before November 27, 1987 and is required to be implemented before startup ,

after the first refueling outage. Since the ICCI. system is a subsy' stem o j PSMS,-ICCI should also be addressed in the licensea's submittal. - Licensee . i action on this issue will be tracked by the NRC as detailed belo .

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l As noted .in section 7 of this report, several system deficiencies have - 4

'been identified regarding RVLIS. The licensee is continuing . to: trouble- 1 shoot, repair and track these items for resolutio .1

NUREG-0737 Itern No. II.F.2 is closed, however, the outstanding issues ,

as outlined below, will be tracked by the inspectors as Unresolved Item (5'0-412/87-60-01):

1 provide additional training / instructions to operators regarding ICCI/ )

PSMS display interpretation ] resolve RVLIS deficiencies (dynamic head RSA, upper range static head channel)  ;

l resolve / complete V & V plan issue for ICCI portion of PSM Licensee resolution of the above items will be reviewed during a future inspectio . Diesel Generator Instrument Vibratio j In the Beaver Valley Unit 2 SER (NUREG-1057, Section .' 9.5.4.1(7)), the _,

staff identified a concern with respect to the effects of engin.e caused -'

vibration on instrumentation and controls needed for proper engine opera-tion (Confirmatory Issue 38). As discussed in Inspection Report 50-412/ ,

87-35, the licensee took vibration data for analysis by Stone and Webster i Engineering Corporation. During this period, the inspector reviewed the j results of the analysis, dated July 23,1987, for adequacy in addressing ]

the staff's concern The report documents the results of vibration measurements on nine panel- h

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mounted components on each of the two diesel generators 'which were take j during engine operation on June 8 - 9, 1987. The frequency and amplitude 1 values were recorded via axial, horizontal and vertical accelerometer {

Five pressure switches were monitored: the starting air low - pressure i switches (2), the coolant pressure switch, the : coolant low pressure l switch, and the fuel oil low pressure switch. Four 3-way solenoid valves were monitored: the air start solenoid valves (2), the temperature. con- i trol air solenoid valve, and the shutdown solenoid valv !

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I In all cases, the observed. vibrations were well below manufacturer test )

data en similar components. For all but one item, the observed vibrations !

were less than one-tenth of the values provided by the manufacturer. Fo j the other item, the co'olant pressure switch, the data was; less than ' one- i seventh of the vendor test va?ues. The available vendor test data did not- 1 always match the field conditions in that the - frequencies (in , hertz) {

varied from those experienced on the diesel generator, but the order of j magnitude reduction in vibration -indicates that the in situ conditions represent a mild environment for the tested component J No deficiencies were identifie . Power Ascension Testing l

The licensee made substantial progress in the power ascension testing program during the inspection period. Details of specialist inspector-coverage of major tests can be found in Inspection ' Reports 50-412/87-59, j 62 and 63. The period August 4,1987 - September 11, 1987, was also sub- '

ject to a special assessment of licensee startup activities through com-pletion of 50% power plateau testing. This assessment was documented in ~ a

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Special Assessment Report which was transmitted to the licensee on October .j 8, 1987. The report notes a very. good overall level of performance with l notable strengths and no major weaknesse l

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Two of the major plant transient tests took place during the period: the '

MSIV closure test and the Loss of Offsite Power Test (LOOP). Both tests were initiated at 30% power and both terminated in Mode 3 (Hot Standby). >

Pre-test discussions between the Nuclear Shift Supervisor and test. super- !

vision enabled the prompt reopening of the MSIVs following MSIV closure j test (see Detail 5.1). A similar strong interface was also evident during {

the LOOP. In that instance, MSIV reopening was deferred for 30 minutes to i assure that all data trends were recaptured,  !

Following plant restart from a brief maintenance outage (September 11 -

September 23,1987), the licensee increased power to 75% for further test- i ing including power step and ramp changes. At the end of the period, the-licensee had completed 75% power plateau testing and was beginning ' to ;

increase power to 90%. '

l No violations were identifie i 11. Inoffice Review of Licensee Event Reports (LERs)

The inspector reviewed LERs submitted to the NRC Region I office to verify that the details of the event were clearly reported, including the accur-acy of the description of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LERs were reviewed:

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LER 87-11-00, Inadvertent Pre-Operational Safety In.fection

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LER 87-11-01, Revision 1 to LER 87-11-00  :

LER 87-12-00, Manual Reactor Trip Due to Dropped Rods .

LER 87-13-00, Inadvertent Realignment of Main Filter Bank Dampers LER 87-14-00, Reactor Trip on Low-Low Steam Generator Level j LER 87-15-00, Reactor Trip Oue to Low-Lew Steam Generator Level i LER 87-16-00, Inadvertent Start of Auxiliary Feedwater Pump i LER 87-17-00, Inadvertent Feedwater Isolation Ove to Procedural Deficiency LER 87-18-00, Reactor Trip Due to De-energized Rod Control Power Cabinet LER 87-18-01, Revision 1 to LER 87-18-00 LER 87-19-00, Reactor Trip / Turbine Trip Oue to Spurious Overspeed Trip 3 Signa '

The above LERs were reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in NUREG 1022. Inspection Report 50-412/ )

87-54 documented the review of the first ten LERs and certain weaknesses !

were noted in completeness of description and detail. During this period, j the inspectors continued discussions with the licensee on these concern l These discussions led to the licensee's revision of one LER (87-11) and a )

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general upgrade of all subsequent LERs submitted. Some deficiencies were t still identified such as the omission in one LER (87-15) of a reference to i a similar event (87-14) as required by 10 CFR 50.73(b)(5). l The inspector noted an overall improvement in the quality of LERs reviewed curing the perio LER adequacy will continue to be monitored by the a irispector as a part of the routine inspection progra :l2. Exit Interview j Meetings were held with senior facility management periodically during the course of this inspection to discuss the inspection scope and findings. A summary of inspectior findings was further discussed with the licensee at ;

the conclusion of the report perio "

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