Text

Forwards Potentially Generic Issue Data Sheet Re Failures of Pilot Inlet Tube Attachments on Target Rock Safety Relief Valves
	ML20117C623
Person / Time
Site:	05000000, Browns Ferry
Issue date:	03/04/1983
From:	Robert Lewis; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	Jordan E, Norelius C, Starostecki R; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE)
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ML20114F930	List: ML20114F926; ML20114G002; ML20114G010; ML20114G018; ML20115A169; ML20115A260; ML20117C191; ML20117C217; ML20117C250; ML20117C291; ML20117C332; ML20117C399; ML20117C408; ML20117C417; ML20117C430; ML20117C470; ML20117C494; ML20117C507; ML20117C526; ML20117C551; ML20117C559; ML20117C564; ML20117C603; ML20117C620; ML20117C623; ML20117C637; ML20117C656; ML20117C662; ML20117C666;
References
	FOIA-84-616 NUDOCS 8505090475
	Download: ML20117C623 (2)
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{{#Wiki_filter:a p * " cg,'o. UNITED STATES NUCLEAR REGULATORY COMMISSION i c %.~ [\\ } REGION 11 8W-w 101 MARIETTA ST, N.W., SulTE 3100 j. [E p ATLANT A. GEORGIA 30303 W# f8~2 5T [87dd b ,.3 o, 'N.... '" MAR,41983 SSINS 9162 MEMORANDUM FOR: Edward L. Jordan Director. Division of Engineering and Quality Assurance, IE ^ Richard W. Starostecki, Director, Division of Project and Resident Programs, RI Charles E. Norelius, Director, Division of Project and Resident Programs, RIII James E. Gagliardo, Director, Division of Resident, Reactor Project and Engineering Programs, RIV Jesse L. Crews, Director, Division of Resident, Reactor Project and Engineering Inspection, RV FROM: Richard C. Lewis, Director, Division of Project and Resident Programs

SUBJECT:

POTENTIALLY GENERIC DEFICIENCY AT BROWNS FERRY IN TARGET ROCK SAFETY RELIEF VALVES The enclosed potentially generic issue data sheet concerning failures of pilot inlet tube attachments on Target Rock safety relief valves is forwarded for information per TI 2500/3. E.c. Richard. Lewis

Enclosures:

1. Pilot Inlet Tube Failure Issue Data Sheet 2. General Electric SIL No.196 CONTACT: G. L. Paulk 205/729-6196 g 50 g 5 841002 BARFIEL84-616 PDR

t _- j 4 Appendix A a' TI 2500/3 / 4/1/80 Data Sheet No.:RII:DPRP-83-05 POTENTIALLY GENERIC ISSUE DATA SHEET Facility Browns Ferry Steam Electric Plant Docket No(s). 50-259, 260, 296 Date of Event 02/05/83_ Inspection or other. Report 1. Brief Description of Issue (Not required if included in supporting data) On February 5,1983, during a reactor scram on Unit 1, Main Steam Relief Valve 1-22 lifted and would not reseat. This resulted in depressurization The of the reactor vessel and an increase in torus water temperature. valve was manually cycled in an attempt to close it but it still remained Subsequent investigation at Wyle Labs indicates that the pilot inlet open. tube welds f ailed thus releasing the pilot inlet tube into the blowdown This path and causing the pilot tube to become wedged in the valve seat. made it impossible for the seat to fully close. Since 1975, there have been several failures at other utilities due to this same cause. This kind of failure is considered to be fatigue due to vibration of the free end of the pilot inlet tube. Such an anomaly may occur in either the 2-Stage or 3-Stage Target Rock reitef valves. 2. How Found'(If appropriate) Incident at Browns Ferry on February 5,1983. 3. Why Considered Potentially Generic (i.e. - reference applicable criteria or give reason) General Electric Service Information Letter (SIL) of November 1982, (SIL No. 196) recommends certain actions be taken when safety relief valves are removed for maintenance or testing. 4. II G. Paulk F. Cantrell/D. Verrelli -Region Originator Section Chief / Branch Chief 5. Other Region Reporting That The Problem Has Also Been Identified By Them Region , Chief , Reporting , Docket No. 6. Evaluation by IE:HQ Bulletin / / Circul'ar / / Information Notice / / Other No further action required

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1750 Chesttiut Street Tower II 3"a7 ai? 5" March 4, 1983 Mr. James P. O'Reilly, Director U.S. Nuclear Regulatory Commission Suite 2900 101 Marietta Street, NW Atlanta, Georgia 30303

Dear Mr. O'Reilly:

TENNESSEE VALLEY AUTHORITY - BROWNS FERRY NUCLEAR PLANT UNIT 1 - DOCKET NO. 50-259 - FACILITY OPERATING LICENSE DPR REPORTABLE OCCURRENCE REPORT BFRO-50-259/83007 The enclosed report provides details concerning unidentified leakage exceeding 5 gpm following a reactor scram. This report is submitted in accordance with Browns Ferry unit 1 Technical Specification 6.7.2.b(2). Very truly yours, TENNESSEE VALLEY AUTHORITY '==% h H. J. Green Director of Nuclear Power Enclosure cc (Enclosure): Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Records Center Institute of Nuclear Power Operations Suite 1500 1100 circle 75 Parkway Atlanta, Georgia 30339 NRC Inspector, Browns Ferry o, &x y+

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1983-TVA 5OTH ANNIVERSARY aeE:us'C::Ortunitv E tes e- .]

~... _ - xv. N: FF AMC, 1520 CST 2-0 T

3. M-; Dell, 1760 CSTI-:

O. L. Fat:1k, NRC TELECOPY TO NRC T. L. Chinn, BFN ()7jh,jj Feb. 7, 1983 C. W. Crawford, 670 CST 2-C A. W. Crevasse, 401 UBB-C G. S. Harrfson, Plt Supt Office U. S. Nuclear Regulatory Commission L. M. Mills, 400 CST 2-C Region II Shift Engineer 101 Marietta Street, NW F. Z. Szczepanski, 417 UBB-C l l Suite 3100 W. C. Thomison, BFN l Atlanta, Georgia 30303 D. L. Williams, W10B85C-K l R0-50-259/83006 y Reported under Technical Specification 6.7.2.a (9) Date of Occurrence: 2/5/83 Time of Occurrence: 0518 Unit 1 Technical Specification Involved: 3.6.G Conditions Prior to Occurrence Unit 1 - Full Power Unit 2 - Refueling Outage Unit 3 - Full Power ~.- Identification and Descrintion of Occurrence Following a reactor scraa, relief valve PCY 1-22 appeared to not fully resent after being actuated by the operator to control reactor pressure. This is based on the acoustic monitor for this valve being in the alarm condition. Annarent Cause cf Occurrence Based on information available, most probable cause was excessive leakage of the pilot valve. Reactor pressure did not decrease to any appreciable extent (which would be indicative of a relief valve stuck open). I Other Related Events None Corrective Action Taken or Planned Replaced pilot valve and solenoid actuator. Valve will be tested during startup to verify operability. G. T. Jo es Power ant Superintendent Browns Ferry Nuclear Plant -/ / ^6 n ~ q g/b c4 N Q3 T

DAILY P.EPORT I' poi DIVISI0ft Of i . t:n p.e,10Egi pan,an;; " *: "I .jurir1. Air 0N ITill OR t.: !:; "t.b Resident in.tirctor On 3/23 during 'ha licensee's' cable tray- 'ci: 50 1:'l 3/24 restraint verit iration, both trains of PHR were declared ieincralile at 7:45 p.m. due ti. cable conduit e'acrt deficiencies to motor operated LPCI iniee. finn valves. The' e.untr rt - support the po.,. iand cabl s.inel t:m a nd enn - suspect durinei i.tuic event. A shu t<! " + ' tb unit was comme:;<!cel imediately. The firC I. h. ', ' and CS systemr.. re-operable. Repair of thn <'l'la supports was ro"iile'r,! at 9:2n p.r1.. Thn unit h." returned to fuli 19-nr. The AE is avaluet.iner 'he as-found condi t ' m ir r design ci iteria. 3 1 i j,. r.s t g..v;. t !+- .frator (Original) ., e 1 ..L9-

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DAILY REPORT INPUT DIVISION OF -PROJIT.1 Aflu RESIDENT PROGRA!45 OA'E _,,"- FAClll1Y NOTIFICATI0ft ITEM OR EVErlT REG 10flAl A '. ' ' ' e%Cle (5<Ywr ~~ Lp/22thelicenseeidentifiedthat8high llatch 2 Resident Inspector On 6 FtrHmmirncr-"~ ~ - Oft: 50-366 6/23 energy Whip Restraints have not been installed /1,,. - r.'. as called for by design drawing. The findiaq /.!l was identified to Georgia Power by Bedal 4 Engineering durinq a drawing audit. Reactor Core Isolation Cooling, Control Rod Drive, Reactor Water Cleanup and Auxiliary Steam Systeins are affected. The unit is in t l y,7, m,e in a refueling outage. L, u n s [c [ lue. I' g *3 94pp ecsbn*liS 'to Jn. $ \\ ba*N > c W* * *& N. l s1 3 / N# hJ Pf</ p/,+ L',y.#,,/-d {; P p s b,'..;1 ,,p (,w 4 'll ', l R I,d,UI l 0fl: f APPROVill lif: t'egiorio! Administrator (Original) ,qp pjje Originator,_,f'. 'Ir i g ilid to r: J. Rogge SeictinnChie(( nr.ncna,i..r.g/c<' ,.........(., .~

i l ? ~ DAILY REPORT INPUT DhVISIONOFPROJECTANDRESIDENTPROGRAMS DATE July N. FACILITY NOTIFICATION ITEM OR EVENT _ REGIO 4?'. J' ' ilatch 2 HQ Duty Officer Reportable Occurrence - The licensee has undertaken a i <> l - Dr. S0-366 7/28 re-verification of valve and instrument alignment fW, ' after their current start-up from refueling, g #. .W2- "'Weh will be completed today. They have identified several instruments not properly aligned which include: ' 'B' Hydrogen Reco[nhiner temperature flow controller and pressure switches for two of four high reactor pressure trips to the recirculation pumps. A complete re-verification of Unit I has begun. A written report is due 8/11. e TPIBUTION: APPROVED BY: "ponal Administrator (Original) - v '" Originator-

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t* 'aa.4 ENGINEERING WORK REQUEST g g R SURRY POWER STATION DATE REC'D 1 PRIOR CODE REQUESTED AsElGNED 2 EWR NO. a 9 -/ f-gf La A(4s nr.) O 3 (wk.) O C (mo.) D D (defer) W-- / / / 4 5YETEM 5 TITLE yw Repair of 1-FW-58,27, and 89 MAR K. N g. 5 DRAWING NO. 7 ARR A/560s. 5 Mk P k MhNGE WWE.VM EN e b g 1-FW-27,58,89 11448-FM-68A Cont. 47' Admin-71, ASME Section XI 10 DESCRIPTION OF PROBLEM Identify valve internal requirements for 1-FW-27,58, and 89, 3" ASME Class 2 Check valves and insure compliance with design specification or construction code. ~ REQUESTED BY 11 DEPT. 12 PHONE EXT. 13 DATE 14 DATE REQRD.15 APPRQVED sY 16 John Wyatt Mech 390 3-16-84 3-17-84 g, [A yxag( RESOLUTION O ATTACHMENT 17 Modifications to the referenced valves were performed at the manuf acturers repair f acility as described in the attached report (MEM'O from A. Rasponti to D. Rickeard dated 3-27-84) and as summarized below: 1. Weld material was added to the valve internals and machined to dimensions that would reduce the play between connecting parts. + 2. Seat material was' upgraded 1 3. Seat surf ace diaineter was decreased to insure full seating of disk on seat. 4. Screwed in seat rings were seal welded i 5. Caps were replaced on two valves 6[ Hinge pin end plugs were replaced and seal welded. The above modifications will not degrade the quality of the valve nor affect the performance of the valve and aux feedwater system for the following reasons: - Documentation by the repair facility was provided to insure that the new l l materials used in the repair of the valve were as good or better than the origina l materials. 5 APETY RELATED 1s IMPLEMENT sE M.R.19 IMPLEMENT M.R ,20 ENGINEER 21 DATE 22 %YES O NO CYE5 $ NO C 5. O -s m lNSTR. [, / g CHANGt FSAR 23 REV. CONTROL 24 COPits.TO 28 LE AD ENGfN R 26 DATE ( 27 O 0.YES @ NO

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FORM #808.24 A JMW 9 l C YES %NO 35 UN N EV6 E WLD 31 sNspG APPRUVAL 32 DETERMINED BY 33 OC APPRQ L 34 DA E */ N REQUIRED 3 ( . O YEs$AFETY QUESThI -.. NO YES ONO

t use of raducers for instaff ation. The pressure drop wi" bc "o Typical #% wing Check )ifa!ve g,eate,1 nan that o, tne ia,g., vai,e that is on y on,tla,:, opon. e and valve life will be greatly extcodcd. The added bonus, of course,is the lower cost of the smallervalve. /' hock valves are automatically actuated. They are opened .,here is no tendency for the seating surfaces of swing check. i ' sustained in the open position by the force of vetoc!!y valves to gall or score, because the disc meets the f.at scat ',oeu.asure, and closed by the force of gravity. Soating fosc andttant tightness is dependen sqqrely 3,lthout rubbjng contact upon closing. The regu ar:y furnished X or XU trim is therefore suitabfe for aff services disc and associated moving parts may be in a constant stato that recuire U trim et temperatures to 1100 F. "A" cnd "!." or of movement il the velocity pressure ::: not sufficient to hold ,,AU' and LU' trims are afso available wnen specified. thO valve in a wide open and stable position. Premature wear Crane cast, steel swing check vafvos in sizes 8" and smal'er and noisy operation or vibration of the moving parts can be can be furnished with outside lever and adjustable weignt avolded by selecting the slze el check valve on the basis of when so ordered. With tr.8 lever and weight mounted so that flow conditions. The minimum vefocity required to held a the welght ass!sts the disc in closing, the valve closes more swing check valve in the wide open and stab'e positfch has rapidly when flow stops, thus minimizing reversal of flow ond been developed by analysis of extensive test data and is ex, resultant surge and shock.With the lever und weight mounted pressed by tie formula: to be!ance the weight of the disc, the valve becomes more .v = 48C */7 m,,4

U v is equal to flow in feet per second and y is the specific volume Swing check valves are used to prevent revorsal of flow in of the fluid in cubic feet per pound. Slzing swing check vatves horizontal or vert! cal pipe lines. In vertical lines, or for any on this basis may often result in the use of valves that are ang!e from horizontal to vertical, they can be used for upward smaller than the pipe in whlen they are used, necessitating the flow only.

? Nils)c f -{4,fe,$8cdy: Strong construction assures maximum safety 4 recommended pressure and temperature range. Beth ffange /[.f# ,,.,qg P and butt weld ends are availabte. No @ Cap: Permits access to hinge and disc without removing valve f rom the line. Class 150 and 300 valves have a male and g J O femate joint. All others use a ring type cao joint. / huise: Designed to close on its own weight to stop backflow O from gaining sufficient velocity to create damaging shoc'. e ( L @ e-i e e J / . O \\ Q-h l 1 p,IL Lg O = ~ lI ? O ~k

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T ill i ICENS([ l' ' I t is I P f. A WRifif H HEPORI. WHITHER li WAS NFVER FREE OF CONTAMINAIION AFIER FA BRIC A-IION. LLNfNAl I H r iP h 8' ulVI.lON DIFECTnk IS AT lilF GNAND CttLF SIIF AI Tf hP fill. Till fril INIERVIft' of THF UlfRt110NS READINESS TFAN INSPLfilON. ALSO IN ATTENDANCF 15 Tile ASSISTANT DIRLCTPA fni: Ilit tilV I S I ON OF 1 ILENSINCe NRR. N 9 .J

a J DAILY'PCPONT - MEGilN !! DATE: 5 L PIE Pist R A, l '# p l # RLGION4L ACil0N f4LILIII taollf!L4fl04 ITEM UN LVLNi si. '.. W ba t tite LICCNSLC I NF ON n4 f loel O la L Y. UP34TE OF D4ILY REPORT OF 4sauST 24, 1943. C4: i ).* o l 4///m3 lifLCIIVE SLPILMdCR 14, 1933, IHL FULLowlNG CH4NGC WILL DE NADO: dR. R. C. MORG41, PLAfai OPERATIO'45 MANAGCR 4T SHLARON HANNIS, WILL ASSUNC THC POSITiord 0F PLANF GLNLR4L M414 GLR AT H. H. NUHl.450N. '. 4 0 4 u i. 'I t f I W L 510 E ta i UP O 4 t a ON GIL5CL G Cr8I R 4 T O R FIRF (PN 4 tl0 DAILY RCPORT of 9/6/81.) \\ u 'e : , 1 - 4 1 ', I ld ie'l C I 0 d 80LLONIrlG THE D(L4 VAL DIESLL GtNr_ggg3g ggag og ppg, CLE4NUP 4 v / / /.4 3 4tle RisIOR4 Tick ARE PROCCEDI.4G. THi DIESEL MANUTACiJPCR WIPdL5ENTATIVE5 ARE ola-S I T L TO ASSIST IHC LICEN5EE IN HIS f 's INVisi!GATIUh. TitC LICLNSEL PL4NS TO FIRST RLPAIR ist DVERHt40 4 s CRA1L WHICH $UFFERED flC 4 T D At14GE 10 THE ELECTRICAL HUS HANS AND t CoreIROLS. THEN THE DIESCL [NGINC G o d E a ta 0 R AND TURuGCH4RGER$ WILL til RCPLACED USING P ART 5 FROM IHL U1li 2 O!ESCL5 WHICil ARC 3 \\ $ltLL IN W 4 2 [Il0U S L STORAGE. Ht4T 4FFCCICO WIRING AND PNCHMATIC \\ l u eil ta b ON THE ENGirlE WILL fil N E Pt. A C L O. F O L L O W i t4 G WATER DLLUGI, THLNL WAS 14 INCHES OF WATCH ON THE FLOOR tlW T INSP(Cil0N5 5HOW, 4 10 04ft, NO 04M4GC 10 ELECTRICAL SWI T Ct.GL A R. THC C4ust UF IHL FULL Ull LCAK 4t4 0 FIRE WAS THL CIRCUMi[RENTIAL DEL 4K OF A 5/4-!NCH DIANET[R TUDING FULL.LINC JUST 00WN5tR[44 0F THC N 4 I ts I PLCHANICAL FU[L PUMP. THL tt RO C L N fuulNG IS DCING EXAHir4C0 FOR CAust OF F4ILURC. THE HRC4K OCCURRLD JUST 00WN5TRE41 0F A COMPRL5510N FITTING 4'40 THE L I Ci tl5 C L IHINKS THE CAUSC W45 I WiliH4fl0N FATEGUE OUE TO It4 A0[4U 4f t SUPPONT OF THE FULL LINE. INE F AILURE 010 NO T OCCUR IN THL TuillNG UR HT THE MCIH00 OL5CK!HC0 IN THE DELAV4L PART 21 NOTIFIC4T10N OF //20s45. I 3 LICLNSLE PER504NEL ISTIN4TE TW3 WEEKS WILL DE NEL0tp FOR NESIONATION. 4 DELUGE VALVE FAILED TO OPCM IN THC FIRL PN0ftCIION SV5 FEM DURI1G IHL (VENT. THE VALWE W45 ILSIED 3UI 3 W ! Ill 0 U T W4TLR PRESSURE ON ONC SIDE. THC TEST WAS SUCCts5FUL. THE LICENSEE 15 STILL FRYING TO CEILRMINE THE C405C. THE VALWE W45 4N AU1064 TIC S P R ! ta K L E R CORPOR4fl04 0F AMERICA, 3 NOOLL C, 6-INCH VALVE. FULLudur OF RCSIORATION OF THL DIEstl !> HEINb r0N00CILO fl Y THL SLNIOR R(5IDENT INSPECIOR AND R E G I 0 t4 AL PCN5 0NT4[L WHO ARE OH-5ITC. REGION IV NUlIFIED OF ( 'N IHC DLLUGL VALVL F4tLURL. ( k N_ t 4 4

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C R use of reductrs for insta!!ation. lbs pressure drop wi'.! be ro lyp] Cal cWing CPdeCX Va!VG gromr inan snat of inarcar v.wn innus on:y partimen, e aA and vc!ve tifo will be greatly extended. The cdried bonus, of check valves are automaticelty actuated. They are opened There is no tendency for the seating sur' aces of sw.ing check. sustained in the open position by the force of vefocity valves to gall or score. because the disc moets the f.at seat '.ssure, and cfoswd by the force of grovity. Sosting foad and sparely wg,out, rubbing contact upon closmg. The regularly wsultant tightness is dependent upon back pressure. Tho furn shed,X or XU, trim is therefore suitable for all services disc and associated moving parts may be in a constant stato ,,Au,pQ,e U trim at temperatures to 1100 F. "A" and tW of movement il the velocity pressure is not suffic! ant to hold and w, trims are also avanable wnen specmee. u.a nrus is n urido npnn snet stah!a nmifinn Ptnmatura yfur u""" '**L*ical *a'"w *I I,. Al,'as In siss: Orr and emnlinr and noisy operation or vibration of the moving parts een ce can be furnished with outside lever and adjustable weight avolded by selecting the sizu uf check valve on the basis of when so ordered. With the lever and weight mounted so that flew conditions. The minimum velocity required to ho!d a the welght ass!sts the disc in Closing, the valve closes more sw'ng check valve in the wide open and stable position has rapidly when flow steps, thus minimizing reversal of flow rind been developed by unutysk of extensive test data and ic cx,, resultant surge and shock. With the lever tind weight mounted pressed by the formuta: .v.== 48vT 5 '/fr h _;y e,,g, to ba!ance the weight of the disc, the valve becomes more sensitive t I w Intet vet Itles. v is equal to flow in feet per seeend and v is the specific votume Swing Check valves are used to prevent reversal of flow in Of the fiuld in cuble feet per pound. Sizing swing check valves horizontal or vertical pipe lines, in vertical lines, or for any cn Hilm Lamia May aften result in the uco of ualves the' are angte from norlzontal lu vaillunt, they can be used for upward smaller than the pipe in whlCh they are used, necessitating the s f b.,fe,@ flow cnly. 'tr i N/U Body: Strong construction assures maximum safety over the recommended pressure and temperature range. Both f!ange /fghs - gP and butt-weld ends are avaliable. @Cey, f% dt. acessa to hingo and dire tarithnfit remnvino valve from the line. Class 150 and 300 valves have a ma:e and ' ~- O female joint. All others use a ring. type cap foint. O @Dise: Designed to oloco on its own weight to sfnp 5: ckflow from gaining sufficient velocity to create dameging shock. M. -r'Th j/ o-

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W b i L' CRAN E : Design Data and geatures: A; SW2NG CM, K C, VALV, i i m ThfT VnIYM finmnIV With Illis DI i i 1n1 'S - h kbb is% O [ IG Y I f Standards: ANSI B16.5, ANSI 16.1 N 10. A e l-B16.34. [' j;,

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c Material-carbon steel. Other materiais avattaere wnen p j l, {~T' g '. ' /t ~ '.:,/ I specified-Cranc No. 5,7,9, LCB and " Arctic" steefs. See L f f ,lpi page 3 for specifications and recommendations. t i y [Y D,f-uysm,,,,,- o Trim-X or XU-sultablo for a broad spectrum of services J to 1100F. Other trims available when specified include: ! l,l Q ,,,'G' E L or LU and A or AU. See pages 3 and 22 for trim descrip-

3

,,,,. -} gt, (;[ tion and service recommendations. 1 o Outside weight and fever to assist in rap'r? closing or for L L I " *' N sensitive balance'at low velocities is avalisbfe en vatves - f-J f Bolted Cap up to 8"in site. < E h( No.148, Threaded

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No.147, Flanged o Drilling templates are shown on page 51. o Flan 0e and facing dimensions are shown on pace 46 ! b Y ess r - e a e a g o Ring joint facing (page 40) con 44 4Vppilod when specified. g 285 psi @-20F to 100': t: 0 c o Butt we! ding ends are bored to match Standard pipe unless otherwise specified. See page 45. }. I i: See page 55 for ratings of other materlafs and temperat i e.

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s c o. - :- s ..n ,5 Y. ENS $cN$I!$ $ 000WE yL 1 ! B34 Dute Power Company ATIN: Mr. H. B. Tucker, Vice President Nuclear Production Department 45 South Church Street Charlotte, NC 28242 Gr.a tlemen: SUCJECT: REPORT NOS. 50-269/83-39, 50-270/83-40 AND 50-287/83-39 On December 28 - 29, 1983, NRC inspected activities authorized by NRC License Nos. DPR-38, DPR-47 and DPR-55 for your Oconee facility. At the conclusion of thL inspection, the findings were discussed with those members of your staff ideritified in the enclosed inspection report. ' Areas examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress. Within the scope of the inspection, no violations or deviations were identified. In accordance with 10 CFR 2.790(a), a copy of this letter and the enclosures will be placed in NRC's Public Document Room unless you notify this office by tele-phone within ten days of the date of this letter and submit written application to withhold information contained therein within thirty days of the date of the letter. Such application must 2.790(b)(1). be consistent with the requirements of Should you have any questions concerning this letter, please contact us. Sincerely, V" Hugh'C. Dance, Chief Project Branch 2 Division of Project and Resident Programs

Enclosure:

Inspection Roport Nos. 50-269/83-39, t 50-270/83-40 and 50-287/83-39~ cc w/ encl: J. E. Smith, Station Manager &\\ ~ r]f % \\ / ri s) cr. ' "' i ShD9 s s j l

~. ..* ( AJ3NIN. ALPOCT 10c II Daft: sECEt!Et.., 1985 h,k[sA' a stansa tsf atiL3 3 N0133g[A180N/SubJECI St&Ca: Pitch of ITEn se EVENT

6. Ann 6uti 12/10/s3 ALPoalAULE OCCWARENCEs DELAWAL DIEEEL 6ENERATSAS (DIV & 1881)

ON 11/4/82 Susa 50-*l6 1233d MP8L NECEIWLD A LETIEa (AON 14AN5 AMERICA DELAWAL, INC., CONCEaNIN6 uMGuALI-ftLD CAuLE ON TNE elWISION 1 AND II DIESEL 6ENERA10a5 PANEL 5 WHICN FAIL (9 INE Itti 383 FLAnt TEST. MPat atPLACED INE DCfECTIVE CANLE IN uh8I 1, AS 54-681

4 CJMMIflie 30 IN PAS-42/37 eN 12/19133, nest aECE1WED A SUPPLEmLNI 10 THE 11/E/ 42 LETTER, NNICM INDICAIED SINEa 6Ef!CIENCIES WITN INE CABLE AI AMbitNI Als ifMPEAATuaES. MP&L CON 18 stas THAT UNIT 1 C ASLE 15 54325f AC10av SINCL II WA5 mE? LACES ON TML MANufAClumLa*5 NOW. 8,1982 RE CenMENDA T ION.....uNa t 2 CAbtL NAS NOT NEEN ALPLACES. THE LICENSEE WILL IILE A EUPPLEMENI AL ALP 0mi TO PnD-82/3T ON IN!5 POTENII AL PA0ptER. SEGION IV NOTIFIES.

""dDP

aunit 1 4ILLh&tt, 12/20 ON 12/19 AT 2:01 P.M.,

WHILE PE8f0AMING THE.MONTMLT CNANNEL ON-LINE TL5T, AC alACIOR TRIP NaEAEER (Riel 410 #AILES TO TRIP IMMEDIATELV; TRIP AL&PONSE TIME W45 APPtenIMATELV 5 SECONDS. INE ATB NAS AEEET AWS TEST [e AGAIN, &a. ,4-410 mL5utilNG IN 4 TRIP AL5PONSE IIME of APPAcalMATELY 5 EECONes. ON IHL INIaD AlltMPI THE STS TRIPPE9 IMMEDIAIELV. NA&ED ON pmEATI5 FACT 0er IE18 aEsutI5 THE LICENSEE PEnf 0aMED ON-LINE TESTING ON INE REMAINING BT85. DC RID Co-2 fouhD SL0d TO OPEAAIE; RESPON5E TIME NAS 2 TO 3 5 ECON 05. 1HL AC WA5 AL50A TMS ARE GENER AL ELECTOIC AK-2-25 AND AK-20-15 TrPE, aE5PLC r avity. AND DC f0s 39gL98 ATE C0As[CTIVE ACTION, THE LICENSEE REPLACED INE AffECILb ATub AND PL Af 0aMLS SAME TESTS ON UNITE 1 AND 2. TESTING ON UNIT 3 IS IN Pddha(55. NO OTHE8 f41LuaE5 UEst DETECIES. TWE LICENSEE 15 Pla#0sMIN6 INE SCHE 9ulCS 6-MONTN PREVENTIVE MAINTENANCE ON UNIT 1 Safastas. IHL alu

AltuaL5 APPEAa TO NE SIMILAR To INE ONES IDENT171ED ON MAINE VANELL AND 544 010faE FACILITIES. WA11IEN ALPOmf SWE 12/30/83. Naa,It AND mL610N BU NOI881ED.

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~ g C UI j MORNING WIPuRf - REGION 11 DAIL: DLLLMDLN 2 T, 19R3 II ) DESCRIPfluN uf ITEM OR EVENT t. seo.ltliv hol l f l[ A lloN/.5UOJ EC T t .l 6 a.. seu puty oll!CLA, S L' P M 4t 8:17 P.M. dN 12/24, INE FIRE PROTECil0N SVSTEM WATER SUPPLY DECPLA5Lo .i t.* I J / rs UELUW T af t 25 0,0'10 GALLONS REQUIRED DV THE TECHNICAL SPECIFICATIONS. THI O CAUSE WA5 A FR0lEN S UP PLV WALVE PLUS IHL FREEZING AND BREAKING of SLVLual 4 SPR I hti. t R HLADS. INE LICEN5EE RESTORED IH( REQUIRfD bATER WOLUML WilHIN TLCHNICAL %PLClflCAfl0N f!ML LIMIT 5. ON 12/26 THE FikL PROTLCIRON SYSitM O ~ W AIE R SUPPtV AGAIN DLCREASED HELOW 250,000 GALLONS. THE CAUSE OF THIS LWtNI WAS PER50NNEL ERROR. THE LICEN5fL P'SIORLD THE WAILP SUPPLT 10 250,0d9 GAtt0NS WifMIN ONE 18008. ROUTINE 10LLOWUP. O ... 6 Hu putt OfflCER, 12/27 ON 12/2T AI 7:57 A.9 EST THE UNIT TRIPPED FROM 1006 POWER ON LUW REACION 4 t/s WAfte LEVEL. THE TRIP RESULIED FOLLOWING A LOSS Of ONE CONDENSAll AND A O CONDtNSAIE HOOSTER PUMP. ALL SV5 TEM 5 FUNCTIONED A5 DESIGNED. THE LIC8H5tl 15 INWL5flLATING THE LOSS Of IHE PUMP. O h4 LIDE NI IN5PICIOR, 12/25 ON 12/2 5 A t 11:28 A.M. GENERATOR OREAktR5 24 AND 2D WERE CPENED [0p A SCHEDuttb L o,5 of LOAD TE57 FROM SOE POWLu. INE LOAD TESI WAS SUC(1558ul O AND INIII Alt o A PL ANNE D 4-WEEK OUIAGF ICR IDDV CURRENT ICSTING UI IHL SilAM GENLRAlups AND LONG-TERM FALQUENCV SUNVLILLANCE TESTING Of SUCH IIIMs As T es t 18-MUNIH INTEGRATED ENGINEERLD 54ftGUARD5 FEATURES TEST. DUNING Cout-O Dowie Wes t L L IN HOT STAND 87 M000, A SMALL 150LAtl0N TRANSFORMER IN IHL SfNCHRONilAll0N CHECK REL AY SYSTEM FOR GENERATOR HREAKERS 24 AND 2U, Shou T I D AND HUNNI. IHE f!RL ORIGADE RtSPONDED. NO OTHER DAMAGt 50 (UN i hul O ROOM LuulPMlHI OCCURRED. THE RESIDLNI INSPECTOR R ES PONDE D WITH IHI flHf URINASL AND UH5ERVLD THC ACTIONS IN THE CONTROL ROOM. INFORMAllbN O NL V. 6 e, ame 1 kiiluthi, 12t/3 I R L i t al. N L L DAILV REPORT of 12/21/85) RLACTOR TRIP DREAKER I R f la ) h t SPoh5L eag>. TIML MLA5UkfMENTS IS IN PROGRESS AND WILL DE CUMPLETED ON ALL THNLI UNil5 i.rs s./8 THIS W!ts. IHL LICENELL 15 PRUCLLDING, CN AN AVAILAUILITV OASIS, IO NiPLAtt i e ".' 6 / ALL PREAktH SH Afi5 AND GE ARING ASSEMBLIES IN RESPONSE TO THL GRLASE IIAR DE N IN G 6 PR OHL L 1 THE LICLNSEL AND GE HAVE CONCLUDED IHAT GREASE HARDENING WAS IHE PRIMARY CAuSE FOR SLOW RESPONSE TIME 5 REPORTED 04 12/21. REGION II IS O I FOLL OWING IHL LICLNSEE'S PROGRAM. im-LILENiet II L L C 0te, 12/l4 REPOR I Al'L t ULLHRRENCE: AT d:20 P.M. ON 12/24, THE PLANT ENTERED TECHNICAL O I - a '.. SPI (iflCAllON ACI!ON SIATEMENT 3.03, WHEN fouR LEVEL TRANSMIIILNS ON IHI RL FUIL I Ni. WAl[R STORAGE TANK FR0ZE AND RECAML IN0PERADLE. INE CAUSE WA5 9 AlfilNC iluMING ele AT IRACF CONTROLS. HLAT IRACING WAS RESTORED AND IHL 'S l *s 5 I R O*I N 8 5 RLIURNED TO OPERAHILIIT WilllIN THE TIME ALLOWED UY INL ALIlON SIAllM6NI. ROUf!NL FOLLOWUP. I 9 g O D 1 5

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( DAT[: DECEM0ER 30, 1983 ......../t4(1t11: 40110ICAllON/5UOJECT DESCRIPl!ON Of ITEM OR LVLNT ....as..sf a h t ', l o t N I INSPECIUR, 12/20 AT T:40 P.M. L5I, ON 12/29/83, UN!I 1 W45 MADE CRITICAL FOLLOWING A RLeutt- ' '. 4 ING 00!AGL TilAT STARTED ON APRIL 16, 1983 MAJOR ACTIV!!![5 DURING Inib OUTAGE INCLUDED NECIRCULAi!0N PIPE INSPLCTION AND REPAIR, SCRAM DISCilANGE VOLUME IMPROVEMENTS AND SUPPSL5510N POOL WORK. ROUTINE FOLLOWUP. "$> o t J..i t 1, 4 4hD 3 IN5PLCluk, 12/30 REFERENCE REGION !! DAILY REPORT of 12/28/83. RESPONSE TIME TESI!NG Of u... ,1-267 AK-2 REACIOR TRIP pAEAKER5 WAS COMPLETED ON 12/29 FOR ALL UN!!5. ALL bs-//a TIME 5 WERE 50 M5EC OR LESS. REGIONAL AND NRR RfrRESENTATIVES 0u5ERVLD >I-23/ PORil0NS Of THE TESTING. .*eI; und i 4HL i LICLNSEL, 12/29 POTENTIAL 5'O.55E - DISCREPANCIES IN CALCULATED P[AK CONTAINMENI TEMPERAIURE:

d-190 St LETTER of 12/16/83, WEST!hGHOUSE INFORMED TWA THAT DURING ANAL"V515 of un.

Pa-5 )I CATAW84 THEV FOUND THAT THE CALCULATED MANIMUM CONTAINMENT IEMPERAIUEE5 FOR DOTH PLANIS WERS NONCONSERVATIVE. 00TH PLANTS HAVE THE ICE CONDEN5LR CON-IAINMENT. PREVIOUSLV CALCULATED PEAK IEMPE R ATURE FOR WATT 5 GAR WAS 32/ DEGREES f. THE NEW PEAK TEMPERATURES ARE CALCULATED To bE 383 DEGREES I f04 IHE MAIN LOWER COMPARTMENT AND 345 DEGREES F FOR THE DEAD END COMPARI-MENT. WESTINGHOUSE FURTHER STATES THAT THE EQUIPMENT SUPPLIED by THEM 15 QUALiflLD f02 THESE HIGHER TEMPERATURES. TWA 15 EVALUATING THE PUTENilAL IMPACI Of lilGHER CALCULATED PEAK IEMPERATURES ON EGUIPMLNT IN THE AREA. IVA 15 AL50 REVIEWING THE IMPACT Of THIS INFORMATION ON SEGUOV AH Wil!CH ALSO HAS AN ICE CONDENSER COMIAINNENT. REGION WILL FOLLOWUP APPLICAulLIIY 10 OTHER REGloN !! ICE COM5ENSOR PLANTS. REGION IV INFORMLD. MI51DENI INSPEEIOM, 12/29 ON THE AFIERN00N Of DECEN8ER 29, 1983, wuRKERS IN ONE Of INE PRODUCTION .. e .... e s. AREAS Of Till Nf 5 PLANT CONDUCTED A SITDOWN STRIKE. WORKERS ALLEGED IHAI 1 HIGH URGANIC SOLVENT FUMES EXISTED IN THE WORK AREA. Nf 5 MANAGEMLNI INDICAIED THAT STATE Of TENNL55EE HEALTH AND SAFETY AUTHORITIES wouLD ut CONIACTED AND AN EVALUATION of INE PR0ut(M WOULD UE MADL. NRC REGION ll INFORNED THE REGIONAL 0$HA OfflCE AND STATE Of TENNL55EE. THE RESIDENI INSPECION 15 CURRENTLV MONiiORING THE SITUAll0N. INFORMAi!ON ONLY.

c. m -, s c Nt!" L E AR hl GM / TOEW COMMISSION l' h 101 M ARI 1 5 RLET.N W ~ g%...j'j m ~,.. otono,ome 3uu o 8 e64 Als GU/AF / Duke Power Company ATTN: Mr. H. B. Tucker, Vice President Nuclear Production Department 422 South Church Street Charlotte, NC 28242 Gentlemen:

SUBJECT:

REPORT NOS. 50-369/83-39 AND 50-370/83-46 On September 29 - October 9, 1983, and February 27, 1984, NRC inspected activities authorized by NRC License Nos. NPF-9 and NPF-17 for your McGuire facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed inspection report. The NRC's concerns relative to the inspection findings were discussed by the Regional Administrator of this office, and Mr. A. C. Thies, Executive Vice President, Power Operations and ycurself, in an enforcement conference held at the Region II office on October 19, 1983. Areas examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress. Enforcement matters arising from this inspection were addressed separately in a letter dated June 8, 1984. In accordance with 10 CFR 2.790(a), a copy of this letter and the enclosures will be placed in NRC's Public Document Room unless you notify this office by telephone within ten days of the date of this letter and submit written application to withhold information contained therein within 30 days of the date of the letter. Such application must be consistent with the requirements of 2.790(b)(1). Should you have any questions concerning this letter, please contact us. Sincerely, E. c. Richard . Lewis, Director Division of Reactor Projects

Enclosure:

(See page 2) rs ^ es-

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ri s ', s!: [- $ M *.* : 0 f f T 1/ 11 &.1 i F. n'. j .t - j n u.u ci ca.w - :. ' 5,,7, J' OCT 14 st3 Duke Power Company ATTN: Mr. H. B. Tucker, Vice President Nuclear Production Department 422 South Church Street Charlotte, NC 28242 Gentlemen:

SUBJECT:

CONFIRMATION OF MEETING - DOCKET NOS. 50-369 AND 50-370 This confirms the telephone conversation between yourself and Mr. R. C. Lewis of my staff on October 11, 1983, for an enforcement conference in Region II Office on October. 19, 1983, at 10:30 a.m. We requested this meeting to discuss recently reported occurrences at the McGuire facility regarding personnel errors and the inadequacy of the verification program for verifying correct performance of operating activities. A proposed meeting agenda is enclosed. Should you have any questions regarding these arrangements, we will be pleased to discuss them. Sincerely, \\ ct.m\\' C dd ames P. O'Reilly gional Administrator

Enclosure:

Proposed Meeting Agenda s cc w/ enc 1: M. D. McIntosh, Plant Manager J. T. Moore, Project Manager 4 e \\\\%N%3 c

ENCLOSURE PROPOSED MEETING AGENDA Duke Power Company Meeting with NRC October 19, 1983. 10:30 a.m. I. Introduction and Purpose of Meeting James P. O'Reilly 'II. Issues of Concern R. C. LewYs a. Loss of Containment Spray, McGuire I b. Containment Spray Pump Recirculation Valve Locked Open, McGuire 2 c. Closed Supply Valve to the Fire,Spri.nkler System in the Containment Annulus, McGuire 2 d. Inadequacy of verification program for verifying correct performance of operating activities III. Duke Power Company Response A. C. Thies IV. Comments and General Discussion Attendees V. Closing Comments James P. O'Reilly 5 e 5

P C tioq'o M g' UNITED STATES . s NUCLEAR REGULATORY COMMISSION o 2 o RE2 ton ll

b 3

101 M ARIETTA STREET, N.W. [ k ATLANTA, GEORGIA 30303 %*****/ J NOV 14 1983 Duke Power Company ATTN: Mr. H. B. Tucker, Vice President Nuclear Production Department 422 South Church Street Charlotte, NC 28242 Gentlemen:

SUBJECT:

MEETING

SUMMARY

- DOCKET N05. 50-369/83-40 AND 50-370/83-47 This refers to the enforcement meeting held between you and others of your staff and members of my staff and myself. The meeting was arranged at our request in the Region II office on October 19, 1983.

This meeting related to activities authorized by NRC license Nos. NPF-9 and NPF-17 for McGuire Units 1 and 2. The subjects discussed are detailed in the enclosed inspection report. Our concerns regarding inoperability of containment spray systems and effectiveness of your verification program for performance of operating activities were expressed to you at the meeting and your positive response to our concerns is appreciated. It is our opinion that the meeting was beneficial and has provided for a better understanding of inspection and enforcement issues. In accordance with Section 2.790 of NRC's " Rules of Practice", Part 2, Title 10, Code of Federal Regulations, a copy of this letter and enclosed will be placed in the NRC's Public Document Room. Should you have any questions regarding this matter, we will be pleased to discuss them. Sincerely, k kdt James P. O'Reilly Regional Administrator

Enclosure:

l Inspection Report Nos. 50-369/83-40 and 50-370/83-47 cc w/ encl: M. D. McIntosh, Plant Manager J. T. Moore, Project Manager n'Ss r~[ QY

pm"E209 UNITED STATES 8

o, NUCLEAR RESULATORY COMMISSION p

2 o R E210N 11 3 101 MARIETTA STREET N.W. ATLANTA, GEORGI A 30303 %,...../ Report Nos.: 50-369/83-40 and 50-370/83-47 ' Licensee: Duke Power Company 422 South Church Street Charlotte, NC 28242 Docket Nos.: 50-369 and 50-370 License Nos.: NPF-9 and NPF-17 Facility Name: McGuire Nuclear Station Units 1 and 2 Enforcement Conf rence at he Region II office Approved by: [w / 2-H.C. (pance, Chief, Project $ ranch No. 2 D6te' Signed Division of Project and Resident Programs

SUMMARY

An enforcement conference was held on October 19, 1983, to discuss the following items: 1. Inoperability of Unit I containment spray systems. 2. Locked open Unit 2 containment spray pump recirculation valve. 3. Closed supply valve to fire protection sprinkler system in Unit 2 contain-ment annulus. 4. Adequacy of verification program for performance of operating activities; independent verification. Details of the event findings are described in NRC Inspection Report Nos. 50-369/83-39 and 50-370/83-46. w 0 A

REPORT DETAILS 1. Personnel Attending Meeting Duke Power Company A. C. Thies, Executive Vice President, Power Operations H. B. Tucker, Vice President, Nuclear Production Department G. E. Vaughn, General Manager, Nuclear Stations K. S. Canady, Manager of Nuclear Engineering Services N. A. Rutherford, System Engineer, Licensing G. A. Copp, Nuclear Engineer M. D. McIntosh, McGuire Station Manager G. W. Cage, Superintendent of Operations W. M. Sample, Projects and Licensing Engineer NRC Region II James P. O'Reilly, Regional Administrator R. C. Lewis, Director, Division of Project and Resident Programs (DPRP) V. L. Brownlee, Chief, Projects Section 2A, DPRP A. J. Ignatonis, Project Engineer, PS 2A, DPRP W. T. Orders, Senior Resident Inspector, McGuire J. M. Puckett, Acting Director of Enforcement F. Jape, Chief, Test Program Section, Division of Engineering and -Operational cograms (CiOP) P. Burnett, Test Program Section, DEOP H. Krug, Test Program Section, DEOP 2. Enforcement Conference of October 19, 1983 The NRC staff addressed the items of concern detailed below and the Duke Power Company (DPC) management provided the description of events with associated corrective actions. The meeting summary notes are described below. The event details are discussed in NRC Inspection Report Nos. 50-369/83-39 and 50-370/83-46. a. Unit 1 Containment Spray System Inoperability of September 29, 1983 DPC described the circumstances which led to the September 29, 1983, discovery of both containment spray system trains being inoperable for approximately four and one half hours. DPC indicated the root cause of the event was an incorrect decision made by the shif t supervisor in not recognizing the tie-in of making both containment spray systems inoperable when taking the RN Pump 1A out of service. Furthermore, a Technical Specification Reference Manual which provides guidance for determining impacted Technical Specifications when declaring a system inoperable was not utilized. In fact, DPC review of this reference manual revealed some shortcomings in

2 that the RN system's impact on NS system was incomplete. For example, loss of RN cooling water to the NS heat exchanger was not addressed in the manual. DPC stated that they are currently looking further into the case of a total loss of containment spray following a postulated LOCA and its impact on containment pressure. They have performed an extensive review of the Technical Specification Reference Manual and held meetings with all station employees by describing recent events. b. Unit 2 Containment Spray Pump Recirculation Valve Found Locked Open Instead of Closed on October 5, 1983 DPC's immediate corrective action was transmittal of a letter to all operations personnel stressing the importance of independent verifica-tion. On October 5-6, 1983, DPC performed a check on all other safety-related system valve alignments requiring independent verifi-cation. Five other valves located in the safety injection and chemical and volume control systems we.re found in proper positions, but not locked. DPC has stated that they do not have procedures on checking status of locked valves every 30 days. However, DPC does verify valve postion status of manual valves and deactivated automatic valves located in the ECCS subsystems ar.d containment penetrations on a 31 day and 18 month frequency. Significance of the event was addressed. DPC has determined that even with the recirculation valve left open, the system would have been operable if required. The pump can deliver approximately 3,500 gpm with the recirculation line open. DPC has also stated that they were evaluating the potential consequences of having water enter from the containment sump in' ) the refueling water storage tank during the recirculation mode following a postulated LOCA. j' DPC indicated that the root causes of the above event were failure of 1/ the auxiliary operator to properly judge the position of the valve and that independent verification was not properly handled. c. Closed Supply Valve to the Unit 2 Fire Sprinkler System in the Containment Annulus As a result of valve alignment verification problems encountered previously as discussed above, DPC expanded their scope of inspection on all locked valves and identified another misaligned valve in the Unit 2 fire protection system on October 9,1983. A supply valve for the sprinkler system inside the containment annulus was found to be closed rather than locked open. The valve was misaligned for sometime and the periodic system valve alignment check, performed every 30 days failed to detect this discrepancy. Licensee investigation disclosed that the individual responsible for performing valve status checks did not visually check the subject valve as required by procedure and falsified records by showing completed work. No other valves in the

3 fire protection system were found out of position and it appears that this was an isolated case. Independent verification per se is not performed on the fire protection system for it is not a safety-related system. DPC's commitment to NUREG 0737 independent verification is addressed only to safety-related systems. d. Independent Verification Program for Performance of Operating Activities DPC described their background, current program, and planned program on independent verification. In March 1981, DPC committed to satisfy the requirements of item I.C.6 of NUREG-0660 and NUREG-0737 which pertains to independent verification. Independent verification of proper system alignment was primarily directed to cover valves and their associated power supplies, but it did not include such activities as components / systems taken out of service. In May 1983, based on Oconee experience of independent verification, the program was expanded to include such items as blank flanges and test caps. Recently, the DPC Administrative Policy Manual (APM) has been revised by expanding independent verifi-cation on all types of components which could affect their ability to perform a safety function and to cover equipment being removed from service. Furthermore, DPC has developed. guidance for defining independent verification, qualified personnel to perform the task and diverse means of verification. The APM was issued to all nuclear stations and DPC committed to fully implement the program as described in the APM. e. Summary and Comments In summary, DPC has stated that they have done the following: (1) Increased their upper management involvement in resolving problem areas brought about by the described events. Management reviews were conducted and meetings were held with all station employees describing the recent events and stressing the importance of i independent verification. (2) DPC performed an extensive review of the Technical Specifications Reference Manual available to aid operations personnel in evalua-ting Technical Specification items. (3) DPC is continuing their evaluation in determining the impact on containment pressure following a postulated LOCA with loss of containment spray. However, their recent calculations show the containment to be capable of withstanding pressures of three to four times design pressure. l a .n. .~,

4 (4) DPC Administrative Policy Manual expanded information on the scope of independent verification and it was issued to all nuclear stations. The program on independent verification will be fully implemented by January 1984. (5) DPC will indoctrinate all of their employees on the need of independent verification and emphasize attention to detail when relative to safety of the plant. The NRC has pointed out to the licensee that greater emphasis should be placed on procedural adherence, that DPC provide better managerial tools in maintaining good operations, and that the operators should be re-examined on their understanding of Technical Specification require-ments. 4 4. .g y,

UNITED ST ATES @ 08?og' NUCLEAR REGULATOGY COMMISSION o,, [ cEGI!N11 o 3 101 M ARIETTA STFIE ET. N.W. ATLANTA, GEoRot A 30303 \\..../ 308W Duke Power Company ATTN: Mr. H. B. Tucker, Vice President Nuclear Production Department 422 South Church Street Charlotte, NC 28242 Gentlemen:

SUBJECT:

PROPOSED IMPOSITION OF CIVIL PENALTY: EA 84-37 FAILURE TO IMPLEMENT TECHNICAL SPECIFICATIONS AND INADEQUATE IMPLEMENTATION OF INDEPENDENT VERIFICATION (

REFERENCE:

INSPECTION REPORT N05. 50-369/83-39 AND 50-370/83-46) A special NRC safety inspection was conducted by NRC Resident and Region-based inspectors ouring the period September 29, 1983 through October 9, 1983, and on February 27, 1984, of activities authorized by NRC Operating License Nos. NPF-9 and NPF-17 for the McGuire facility concerning violations identified by the licensee. An Enforcement Conference was held in the Region II office on October 19, 1983 to discuss the significant findings of the inspection. Mr. James P. O'Reilly, Regional Administrator, Region II, and Mr. A. C. Thies, Executive Vice President, Nuclear Production Department, Duke Power Company, and members of their respective staffs, were present. The first violation concerned the mispositioning of a containment spray recirculation valve. The violation was identified on October 5, 1983 while Unit 2 was operating at 89% power. At this time, the licensee discovered that the A train containment spray recirculation valve (2NS-8) was locked open instead of closed as required by plant procedures. A review of the licensee's records indicated that the valve had last been opened during the performance of test PT/2/A4208/01B on September 14, 1983 and had apparently not been closed at the conclusion of the test. In addition, a second independent valve position verification check failed to identify that the valve was mispositioned. Had a loss of coolant accident occurred, with the system in this configuration, contaminated sump water could have been recirculated back to the fuel water storage tank (FWST) and to the outside environment. Using conservative assumptions, radiciodine venting from the FWST could have subjected the public, at the site boundary, to a thyroid radiation dose above that predicted for the Final Safety Analysis Report postulated accident. This incident resulted primarily from failure of plant personnel to implement the requirements of NUREG-0737 by performing a proper independent verification of a recirculation valve position for a containment spray pump. This violation of NRC requirements has been categorized as a Severity Level III. CERTIFIED MAIL RETURN RECEIPT REQUESTED ~ e)

8 64 Duke Power Company 2 The second violatlon involved the inoperability of the Unit I containment spray system. On September 28, 1983, at 10:30 p.m., while Unit I was operating at 100% rated power, train B of the containment spray system was declared inoperable because power was lost to a train B containment pressure transmitter. At 11:30 a.m. on September 29, 1983, train A of the nuclear service water system was declared inoperable. As a result, there was no nuclear service water avail-able to provide cooling to the A containment spray heat exchanger or the A containment spray pump motor cooler. Consequently, train A of the containment spray system was rendered inoperable. With neither train of the containment spray system operable, the provisions of Technical Specification 3.0.3 were applicable, and licensee was required within one hour to initiate action to place the Unit in a mode in which the specification does not apply, but operations personnel failed to recognize this requirement. This violation of NRC requirements has been categorized as Severity Level III. A third violation relates to the inoperability of the Unit 2 annulus sprinkler system from February to October 1983. At the conclusion of the February 8, 1983 Unit 2 Fire Protection Header Test (PT/2/A/4400/01L), fire protection supply valve IRF989 was left closed because the test procedure mistakenly called for the valve to be left in a closed position. With this valve closed, the Unit 2 annulus sprinkler system was rendered inoperable. The misposition of the valve was not discovered until a plant-wide audit of locked valves was completed in October of 1983. The audit was conducted in response to finding containment ~ spray valve 2NS-8 mispositioned. A licensee investigation of the matter revealed that the individual who had been responsible for conducting the Fire Protection Monthly Test (PT/0/A/4400/01C) had failed to verify the position of valve IRF989 and improperly documented his verification. The licensee promptly discharged the employee and verified the position of all valves for which the employee had been responsible. This violation of NRC requirements has been categorized as a Severity Level IV. The first violation is specifically associated with inadequacies in your independent verification program. In the Duke Power Company response to the Notice of Violation and Proposed Imposition of Civil Penalties dated June 2, 1983 for the Oconee Nuclear Station, you proposed improvements in your existing indepenecat verification program. Those improvements and lessons learned were to be incorporated into the operational activities at McGuire and Catawba. The violation as described above does not indicate that those improvements were effective. To emphasize this concern and the need for Duke Power Company to provide additional attention to the administrative controls for operation, particularly the need to impTement independent verif1 cation as provided for by NUREG 0737, I have been authorized, after consultation with the Director, Office of Inspection and Enforcement, to issue the enclosed Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $40,000 for the Severity Level III violation involving independent verification activities. The base penalty of $40,000 could have been increased by 25% because the corrective action for previous similar violations at Oconee has not been effective. However, because you identified and reported the violation, I have decided not to escalate the proposed civil penalty.

208M Duke Power Company 3 The violation of regulatory requirements identified in the enclosed Notice of Violation regarding the inoperability of the containment spray system is categorized as a separate Severity Level III violation. The base value of a civil penalty for a Severity Level III violation is $40,000. However, a review of the circumstances of the event and your performance history in this general area of concern did not reveal problems similar to those in the area of independent verification. For this reason, and after consultation with the Director of the Office of Inspection and Enforcement, I have been authorized to mitigate the base civil penalty for this violation by 100% and to issue the enclosed Notice of Violation. You are required to respond to the enclosed Notice and you should follow the instructions specified therein when preparing your response. Your response should specifically address the corrective actions taken or planned with regard to satisfying NUREG 0737 requirement I.C.6. In your response, appropriate reference to previous submittals is acceptable. In accordance with 10 CFR 2.790 of the NRC's " Rule of Practice," Part 2, Title 10, Code of Federal Regulations, a copy of this letter and the enclosure will be placed in the NRC's Public Document Room. The response directed by this letter and accompanying Notice are not subject to the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, PL 96-511. Sincerely, W James P. O'Reilly Regional Administrator

Enclosure:

Notice of Violation and Proposed imposition of Civil Penalty cc w/ enc 1: M. D.-McIntosh, Plant Manager J. T. Moore, Project Manager

NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY Duke Power Company Docket Nos. 50-369 and 50-370 McGuire Units 1 and 2 License Nos. NPF-9 and NPF-17 EA 84-37 As a result of the inspections conducted from September 29 through October 9, 1983, and on February 9, 1984, three viciations of NRC requirements were identified. In accordance with the General Policy and Procedure for NRC Enforcement Actions 10 CFR Part 2, Appendix C, and pursuant to Section 234 of the Atomic Energy Act of 1954, as amended ("Act"), 42 U.S.C. 2282, PL 96-295, and 10 CFR 2.205, the particular violations and associated civil penalty are set forth below: 1. VIOLATION ASSESSED A CIVIL PENALTY Technical Specification 6.8.1 states in part: Written procedures shall be established, implemented, and maintained covering the activities referenced below: a. The applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978; b. The applicable procedures required to implement the requirements of NUREG-0737;... Plant test procedure PT/2/A4208/01B requires that the containment spray recirculation valve 2NS-8 be locked closed at the conclusion of the test, and a second independent verification by a second qualified individual of the valve position is required at the conclusion of the test. Contrary to the above, on September 14, 1983, at the conclusion of test PT/2/A4208/01B, the Unit 2 containment spray recirculation valve, 2NS-8, was locked open instead of closed as required by plant test procedure PT/2/A4208/01B. The second independent verification by a second qualified operator of the position of valve 2NS-8 failed to detect that the valve was incorrectly positioned. This is a Severity level III violation (Supplement I). (Civil Pena'lty - $40,000) II. VIOLATIONS NOT ASSESSED A CIVIL PENALTY A. Technical Specification 3.6.2 states: Two independent containment spray systems shall be OPERABLE with each spray system capable of taking suction from the FWST on a Containment Spray Actuation Signal and transferring suction to the containment spray. APPLICABILITY: fiODES 1, 2, 3, and 4. O h r _ /g r/g zp u / s/" P as

s Notice of Violation 2 ACTION: With one containment spray train inoperable, restore the inoperable spray train to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours; restore the inoperable spray train to OPERABLE status within the next 48 hours or be in COLD SHUTDOWN within the following 30 hours. Technical Specification Definitions define OPERABLE to mean: A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function (s), and when all necessary attendant instrumentation, controls, a normal and an emergency electrical power source, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystam, train, component or device to perform its function (s) are also capable of performing their related support function (s). Technical Specification 3.0.3 states in part: When a Limiting Condition for Operation is not met, except as provided in the associated ACTION' requirements, within one hour, action shall be initiated to place the unit in a MODE in which the specification does not apply by placing it, as applicable, in: 1. At least HOT STANDBY within the next 6 hours, 2. At least HOT SHUTDOWN within the following 6 hours, and 3. At least COLD SHUTDOWN within the subsequent 24 hours... Contrary to the above requirements, on September 28, 1983, Unit I was in Operational Mode 1 for approximately 4 hours and 40 minutes with both trains of the containment spray system inoperable. During this time, no action was initiated pursuant to Technical Specification 3.0.3 to place Unit 1 in a mode in which Technical Specification 3.6.2 did not apply. This is a Severity Level III violation. B. Technical Specification 4.7.10.2 states in part that: i ... required Spray and/or Sprinkler Systems shall be demonstrated OPERABLE...

a. At least once per 31 days, by verifying that each valve (manual, power-operated, or automatic) in the flow path is in its correct position,...

O* Notice of Violation 3 Contrary to the above, the 31 day surveillance for the annulus sprinkler supply valve was not performed on Unit 2 from March to October 1983. Failure to perform the surveillance resulted in fire protection supply valve IRF989 being left mispositioned from February 8 to October 1983. This is a Severity IV violation. Pursuant to 10 CFR 2.201, Duke Power Company is hereby required to submit to the Director, Office of Inspection and Enforcement, USNRC, Washington, D. C.

20555, with a ccpy to this office, within 30 days of the date of this Notice a written statement or explanation, including for each alleged violation:

(1) admission or denial of the alleged violation; (2) the reasons for the violation if admitted; (3) the corrective steps that have been taken and the results achieved; (4) the corrective steps that will be taken to avoid further violations; and (5) the date when full compliance will be achieved. Consideration may be given to extending the response time for good cause shown. Under the authority of Section 182 of the Act, 42 U.S.C. 2232, the response shall be submitted under oath or affirmation. Within the same time as provided for the response required above under 10 CFR 2.201, Duke Power Company may pay the civil penalty in the amount of $40,000 for the violation assessed a civil penalty, or may protest imposition of the civil penalty, in whole or in part, by a written answer. Should Duke Power Company fail to answer within the time specified, the Director, Office of Inspection and Enforcement, will issue an order imposing the civil penalty in the amount proposed above. Should Duke Power Company elect to file an answer in accordance with 10 CFR 2.205 protesting the civil penalty, such answer may (1) deny the violation listed in this Notice in whole or in part, (2) demonstrate extenuating circumstances, (3) show error in this Notice, or (4) show other reasons why the penalty should not be imposed. In addition to protesting the civil penalty, in whole or in part, such answer may request remission or mitigation of the penalty. In requesting mitigation of the proposed penalty, the five factors addressed in Section IV(B) of 10 CFR Part 2, Appendix C, should be addressed. Any written answer in accordance with 10 CFR 2.205 should be set forth separately from the statement or explanation in reply pursuant to 10 CFR 2.201, but may incorporate by specific reference (e.g., citing page and paragraph numbers) to avoid repetition. The attention of Duke Power Company is directed to the other provisions of 10 CFR 2.205 regarding the procedure for imposing a civil penalty. Upon failure to pay the penalty due, which has been subsequently determined in accordance with the applicable provisions of 10 CFR 2.205, this matter may be referred to the Attorney General, and the penalty, unless compromised, remitted, or mitigated may be collected by civil action pursuant to Section 234c of the Act, 42 U.S.C. 2282. FOR THE NUCLEAR REGULATORY COMMISSION !M James P. O'Reilly Regional Administrator Dated in Atlanta, Georgia thispay of June 1984

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ACCESSION NOR: 8404000295 CUC.0 ATE: 84/03/19 NOTAPIZED: NO U0CKET a FACIL:50-277 Peach Bottom Atomic Power Station, Unit 2, Philadelph 05000277 50-278 Peacn Bottom Atomic Power Station, unit 3, Fn11adelon 05000273 AUTH.NAME AUTHUR ArFILIATION STAROSTECKI,R.

Division ot Proj ec t 3 Resicent Programs RECIP.9AAE RECIPIENT AFFILIATION OALTROFF,S.L. Philadelpnia Electric Co. SudJECT: Forwarcs IE Insp nepts 50-277/84-03 L 50-273/aa-03 on 840113-0229 & notice of violation. DISTRIBUTION CUDE: IE01S COPIES RECEIVE 0:LTR _L ENCL d. 5IZE: Old[.hbf__ TITLE: General (50 Okt)=Insp Rept/ Notice of Violation Response NOTES: RECIPIENT COPIES RECIPIENT CODIES IV CODE /NAME LTTR ENCL ID Cnnr z* AME LTTR ENCL NRR ORS 4 BC 1 1 ( GEARS,_G j 1 1 INTERNAL: AEUD 1 1 ELD /HOS4 1 1 IE FILE 01 1 1 IE/DOASIP/ORPb i 1 IE/ES 1 1 NRR/DSI/RAB 1 1 EXTERNAL: ACRS 2 2 LPOR 1 1 NRC PDR 1 1 NSIC 1 1 NT13 1 1 l O j TOTAL NUMBER OF COPIES REwu1 RED: LTTR 14 ENCL 14 ~

q MAR 19 :534 Docket / License: 50-277/CPR-44; 50-278/DPR-56 Philadelphia Electric Ccmpany ATTN: Mr. S. L. Daltroff Vice President Electric Production 2301 Market Street Philadelphia, Pennsylvania 19101 Gentlemen:

Subject:

Combined Inspection 50-277/84-03; 50-278/84-03 This transmits the findings of the routine resident safety inspection by Messrs. A. R. Blough and J. H. Williams on January 13 - February 29, 1984 at the Peach Bottom Atomic Power Station, Delta, Pennsylvania. These findings were based on observation of activities, interviews, measurements and document reviews, and have been discussed with Mr. R. S. Fleischmann of your staff. Apparent violations of NRC requirements are cited in Appendix A and categorized in accordance with 10 CFR 2 Appendix C and Federal Register Notice 47 FR 9987 (March 9, 1982). A reply is required and should be prepared in accordance with Appendix A. The requirement that you reply is exempt from clearance by the Of-fice of Management and Budget.under the Paperwork Reduction Act of 1980, PL 96-511. The enclosed report provides the details of four events in which it appears that a Technical Specification Limiting Condition for Operation was not met (one at Unit 2 and three at Unit 3). Specifically, these were: two separate instances in which primary system heatup rate was exceeded; one instance in which feedwater injection valves were not closed as required which resulted in an unplanned cool-down with the reactor vessel partially pressurized; and, one instance in which the slow scramming of a control rod during a reactor scram was not recognized. We are concerned that these events occurred; in particular, because they involve operating crews of both units, happened over a short time period and, for at least three, more attention by the operating crew could have prevented the event. As a result, we have the following questions: (1) why did these events occur; (2) is there sufficient attention to plant evolutions and conditions by opera-tions personnel during relatively routine operational events; and (3) what ac-tions are being taken by Philadelphia Electric Company as a consequence of these events? Following receipt of this letter, we will be contacting you to schedule an Enforcement Conference to discuss these concerns. In accordance with 10 CFR 2.790(a), a copy of this letter and the enclosures will be placed in the NRC Public Document Room unless you notify this office, by tele-phone, within ten days of the date of this letter and submit written application within thirty days of the date of this letter. Such application must be consis-tent with the requirements of 2.790(b)(1). The telephone notification of your intent to request withholding, or any request for an extension of the 10 day period which you believe necessary, should be made to the Supervisor, Files, Mail and Records, USNRC Region I, at (215) 337-5223. OFFICIAL RECORD COPY 108/BLOUGH/3/12/84 - 0001.0.0 ^ ^G,0 6n ;; - - - - - 03/12/84 PD

R ADOCK 05055jf7 f/

lll PDR A.p p .l

F., ~ Philadelphia Electric Comoany 2 IJAR 1 9 1934 Your cooperation with us is appreciated. Sincerely. OrL.!.n:.131 ::d 3y: Richard W. Starostecki, Director Division of Project and Resident Programs

Enclosures:

1. Appendix A, Notice of Violation 2. NRC Region I Combined Inspection Report 50-277/84-03; 50-273/84-03 cc w/encis: R. S. Fleischmann, Station Superintendent Troy B. Conner, Jr., Esquire (Without Report) Eugene J. Bradley, Esquire (Without Report) Raymond L. Hovis, Esquire (Without Report) Michael J. Scibinico, II, Assistant Attorney General (Without Report) Public Document Room (PDR) Local Public Document Room (LPDR) Nuclear Safety Information Center (NSIC) NRC Resident Inspector Commonwealth of Pennsylvania bec w/encis: Region I Docket Room (with concurrences) Troy B. Conner, Jr., Esquire Eugene J. Bradley, Esquire Raymond L. Hovis, Esquire Michael J. Scibinico, II, Assistant Attorney General Senior Operations Officer (w/o encis) OPRP Section Chief D. Holody, RI T. Martin, RI A RP R RP RI DPRP RI RP )/ /a lough /meo pr p K 1 mig Sta s< eck:

4.

bl1h0" hg 3*U*N j

OFFICIAL RECORD COPY 108/BLOUGH/3/12/84 - 0002.0.0 03/12/84

APPENDIX A NOTICE OF VIOLATION Philadelphia Electric Company Docket / License: 50-277/DPR-44 Peach Bottom Units 2 and 3 50-278/DPR-56 As a result of the inspection conducted on January 13 - February 29, 1984, and in accordance with the NRC Enforcement Policy (10 CFR 2, Appendix C) published in the Federal Register on March 9, 1982 (47 FR 9987), the following violations were identified: A. Amendment 53 (dated May 23, 1979) to Facility Operating Licenses OPR-44 and DPR-56, and its associated Fire Protection Safety Evaluation, require imple-mentation of a program for inspection and lubrication of yard hydrants in the fall of each year, including a maintenance program to ensure that no standing water remains in the hydrant. Contrary to the above, an adequate hydrant maintenance program was not imple-mented, in that deficiencies involving standing water in Hydrant H-5, al-though noted and documented during inspection on November 1, 1983, were allowed to persist until about January 23, 1984 which led to the hydrant being inoperable for some undetermined time due to freezing. This is a Severity Level IV Violation (Supplement I) applicable,to DPR-44 and OPRP-56. B. 10 CFR 50 Appendix B Criterion XVI, Corrective Action, as well as Section 2.16 of the licensee's approved Quality Assurance Plan (Revision 4, January 1980, and subsequent revisions), requires measures to assure that conditions adverse to quality are promptly identified and corrected. Chicago Bridge and Iron Nuclear QA Manual for ASME Section III Products, Issue 8, March 22, 1978, applicable to major torus structural modifications, requires in Divi-sion 4, Section 14.4, that all nonconformances except (1) surface irregular-l ities that are eliminateif by surface conditioning, and (2) welded correc-tions to welds made during the course of deposition to be reported, docu-mented, and formally dispositioned. If a nonconformance is repaired, the j repairs are required to be per an approved repair procedure or contract drawing. l Contrary to the above, during torus structural modifications in the Spring 1982 Unit 2 outage, a nonconforming condition (i.e., through-wall damage to the torus vent header shell in the area of a stiffener support plant weld) was not reported, documented or formally dispositioned. Further, the damage was partially repaired without use of an approved repair procedure or con-tract drawing. These nonconformances were not identified or corrected until February 20, 1984. This is a Severity Level IV Violation (Supplement I) applicable to DPR-44. \\ OFFICIAL RECORD COPY 108/BLOUGH/3/12/84 - 0003.0.0 ,n, may 03/12/84 M D6 E 05060277 l G PDR Me

Appendix A 2 Pursuant to the provisions of 10 CFR 2.201 Philadelphia Electric Comoany is hereby required to submit to this office within 30 days of the date of the letter transmitting this Notice, a written statement er explanation in reply, including for each violation: (1) the corrective steos wnich have been taken and the re-suits achieved; (2) the corrective steps which will be taken to avoid further violations; and (3) the cate when full comoliance will be achieved. Where good cause is shown, consideration will be given to extending the response time. e 4 4 S OFFICIAL RECORD COPY 108/BLOUGH/3/12/84 - 0004.0.0 03/12/84

U. S. NUCLEAR REGULATORY COMMISSION 50-277: 831223 i Region I 50-278: 831117 831213 50-277/ 84-03 831219 Report No. 50-278/ 84-03 8401C6 Docket No. 50-277 50-278 DPR-44 c License No. DPR-56 Priority

ategory c

i Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 i Facility Name: Peach Bottom Atomic Power Station Inspection at: Delta, Pennsylvania l Inspection Con cted: h.A4) 3 k Inspectors: l jpA. . 81 bih, Sr. Resident inspector date signed 1 . f. a 3/a/e4 l l J! H. WiTYiams, Resident inspector 'date signed 3 Approved by: / / kowell E. Tripp, Chief Reactor Projects Section 3A Inspection Summary: January 13 - February 29, 1984 (Combined Insoection Report 50-277/84-03 and 50-278/84-03) Areas Inspected: Routine, on-site regular and backshift resident inspection (131 hours Unit 2; 137 hours Unit 3) of accessible portions of Unit 2 and Unit 3, oper-ational safety, radiation protection, physical security, control room activities, licensee events, IE Bulletin and Circular followup, surveillance testing, fire protection, comittee activities, and outstanding items, t Results: Except as follows, activities appeared to be conducted safely and in I accordance with regulations: (1) large number of annuntiators lit routinely in the Control Room (Detail 3.1.3); (2) excessive heatup rate Unit 2 and Unit 3 (Detail 3.2.1 and 3.2.2); (3) unplanned cooldown with slight reactor vessel pressurization ( weld repair (Detail 4); (6)drant maintenance (Detail 2.11); (5) torus vent heade I (Detail 3.2.3); (4) fire hv operation with inoperable control rod (Detail 10.2). I Mk o$$$[77 G PDR

DETAILS 1. Persons Contacted J. K. Davenport, Maintenance Engineer G. F. Dawson, I&C Engineer

R. S. Fleischmann, Station Superintendent A. Fulvio, Site QA Engineer A. Hilsmeier, Senior Health Physicist W. MacFarland, Project Engineer, Construction Division J. Mitman, Results Engineer D. O'Rourke, Engineer, Mechanical Engineering Division S. R. Roberts, Operations Engineer
D. C. Smith, Assistant Station Superintendent S. Q. Tharpe, Security Supervisor W. T. Ullrich, Superintendent, Nuclear Generation Division D. Warfel, Assistant Maintenance Engineer A. J. Wasong, Reactor Engineer J. E. Winzenried, Technical Engineer Other licensee employees were also contacted.
Present at exit interviews on site and for summation of preliminary inspection findings.

2. Previous Inspection Item Update 2.1 (Closed) Unresolved Item (277/83-29-01' 278/83-28-02), improperly read radiographs. This item is superceded by unresolved item 277/84-05-01, 278/84-05-01. 2.2 (Closed) Inspector Follow Item (278/81-10-02), review effectiveness of licensee actions to preclude inadequate blocking permits. Licensee actions included reinstructing personnel and requiring shift supervi- + sian review of each permit. Subsequently, the licensee initiated a program to upgrade all blocking sequences. This program was reviewed in Inspection 83-02. These actions have resulted in improved blocking permit system effectiveness. However, on October 24,1983, Unit 3 was manually scrammed, due to post-maintenance testing complications initi-ated by failure to remove stop logs from a circulating water pump suction bay after maintenance. The stop logs had not been documented on the blocking permit. The licensee has taken corrective action re- - garding tagging of stop logs. The inspector asked whether other similar situations might exist, where portions of unique blocking situations might not be formally documented. The licensee stated that he had attempted, during his review of the stop log event, to identify other similar situations, but none were found. 2.3 (Closed) Violation (278/83-27-03), failure to use up-to-date revisions of surveillances and of a post-scram check-off list. The licensee determined that the out-of-date procedures were obtained from an uncon-trolled book of blank startuo tests and from uncontrolled personal files. l 1 se

3 The licensee deleted the book of blank startup tests, instructed per-sonnel to destroy personal files of test procedures, and directed personnel to either obtain blank procedures from controlled files or duplicate them frem controlled procedure books. The inspector reviewed the licensee's instruction memo and verified that operators and STAS were familiar with its directions. No further uses of out-of-date procedures were identified. 2.4 (Closed) Violation (278/83-27-04), failure to review a post-startup check-off list. The licensee's response stated that qualified per-sonnel had reviewed the completed check-off but not signed for the review. The licensee corrected the specific omission and counselled the senior staff involved. The inspector verified this through dis-cussions with licensee personnel. 2.5 (Closed) Violation (277/83-12-01, 278/83-12-01), failure to maintain jumper status and to use the proper revision of a routine surveillance test. The individual responsible for the jumper log error was coun-selled. Also, use of the jumper log was suspended, and the suspension remains in effect. Additional follow-up of jumper control is assured through open item 278/83-09-03. Additionally, the licensee's surveil-lance test coordinator was instructed to verify the revision numbers on routine surveillances prior to issuing the tests for performance. The inspector verified this and checked a sampling of completed tests. No cases of use of outdated revisions were noted. 2.6 (Closed) Unresolved Item (277/83-12-02), Unit 2 rod position indication jumper was left installed unnecessarily during operation. The jumper was removed during the original inspection. Use of the jumper log had been suspended; that suspension remains in effect. The licensee event report for previously identified Unit 3 jumper control problems (refer-ence inspection report 83-09) was updated to include a discussion of the unnecessary Unit 2 jumper. The inspector had no further-questions. 2.7 (Closed) Violation (277/80-33-03, 278/80-26-03), failure to follow visitor escort procedures. The escort, a security guard, was disci-plined and retrained. Other guards who act as escorts in similar situations (i.e., one escort simultaneously responsible for a visiting truck and its driver) were also reinstructed. The inspector observed several visiting trucks during the inspection; all were properly escorted. 2.8 (Closed)InspectorFollowItem(278/83-09-02), discuss in-plant work control problems, such as taped over door alarms, at SALP. This issue was discussed in detail at the June 1983 SALP meeting. 2.9 (Closed) Violation (278/80-07-04), broken fire barrier. The licensee revised his inspection procedure for temporary barriers. This was re-viewed in inspection 277/83-32; 278/83-32. The licensee also cautioned maintenance and construction personnel to exercise care with fire barrier seals and to report observed deficiencies. The inspector had no further questions. .O b

o 4 2.10 (Closed) Violation (277/81-19-02), improper actions for an inoperable isolation valve. In addition to disciplining or counselling all persons involved, the Station Superintendent held meetings with all operations personnel to stress the importance of adhering to proced-ures and Technical Specifications. The inspector verified that the meetings had been conducted. 2.11 (Closed) Unresolved Item (277/83-37-02), adecuacy of fire hydrant in-spections, maintenance, and winterization. As noted in the original inspection, yard hydrants had been inspected anc lubricated on November 1, 1983, per surveillance test ST16.15, Revision 1, January 6,1981, Fire Hydrant Lubrication. Hydrant H-3 was noted as having a leaking shut-off valve and Hydrant H-5 did not drain. Although maintenance requests were issued, the repairs had not been started. ST16.15 did not specify cor-rection or compensation before winter for noted deficiencies that could lead to problems in cold weather. The inspector expressed concern that the hydrants may have frozen. The licensee reviewed this issue and detennined that H-3 was not of concern because it had more than adequate drain capacity (below the frost line) to compensate for its slight shut-off valve leakage. On or about January 23, 1984, the licensee inspected hydrant H-5 and found it to be inoperable due to an ice alug that extend-ed up to the hose connections. The licensee began thawing'the hydrant and investigating the problem. Amendment 53 to Facility Operating Licenses DPR-44 and DPR-56, May 23, 1979, required the licensee to complete actions listed in Section 3.1 of the Fire Protection Safety Evaluation (FPSE), also dated May 23, 1979. FPSE Section 3.1.14 required each hydrant to be inspected and lubricated in the fall of each year. Section 4.3.1 amplified this by stating, "a maintenance program will be established for the hydrants which will require that each hydrant have the caps removed, threads lubricated and barrel checked in the fall of each year to insure that there is no standing water remaining in the barrel or at the hydrant valve." The inspector concluded that the licensee had not implemented an adequate maintenance program, in that the hydrant H-5 deficiency noted during a required inspection was allowed to per-sist until the hydrant became inoperable due to freezing of standing r water in the hydrant. Therefore, this item is reclassified from an unresolved item to an apparent Violation (277/84-03-04; 278/84-03-07). 3. Plant Operations Review 3.1 Facility Tours Daily tours and observations included the Control Room, Turbine Building (alllevels),ReactorBuildings(accessibleareas),RadwasteBuilding, Diesel Generator Building, yard perimeter outside the power block (in-cluding Emergency Cooling Tower and torus dewatering tank), Security Building, vehicular control, the SAS and power block control points, security fencing, portal monitoring, personnel and badging, control of Radiation and High Radiation areas (including locked door checks). TV monitoring capabilities, and shift turnover.

5 3.1.1 Control Room staffing frequently was checked against 10 CFR 50. 54(k), and the Technical Specifications. Presence of a senior licensed operator in the control rocm was verified frequently. 3.1.2 Monitoring Instrumentation. The inspector frequently confirmed that selected instruments were operating and indicated values were within Technical Specification requirements. ECCS switch positioning and valve lineups were verified based on control room indicators and plant observations. Observations included flow setpoints, breaker positioning, PCIS status, radiation monitoring instruments, and containment parameters. 3.1.3 Off-Normal Alarms. Selected annunciators were discussed with control room operators and supervision to assure they were knowledgeable of plant conditions and that corrective action, if required, was being taken. The operators were knowledgeable of alam status and plant conditions. However, the inspector noted that the number of continuously lit annunciators has been increasing. Most lit annunciators are the result of faulty instruments, faulty annunciators or minor equipment problems. As of the end of this inspection about 50 annunciators were lit in the combined Unit 2 and Unit 3 control room. The inspector will follow the licensee's actions to resolve the annunciator problems. 3.1.4 Fluid Leaks. The inspector observed sump status, alams, and pump-out rates, and discussed leakage with licensee personnel. 3.1.5 No significant or unusual piping vibration was found. 3.1.6 Environmental Controls. The inspector observed visible main stack and ventilation stack radiation recorders and periodically reviewed traces from backshift periods to verify that radioactive gas release rates were within limits and that unplanned releases had not occurred. 3.1.7 Fire Protection. The inspector observed control room indications of fire detection and fire suppression systems, spot-checked for proper use of fire watches and ignition source controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment stations. 3.1.8 Housekeeping. The inspector observed housekeeping conditions, including control of combustibles, loose trash and debris; and spot-enecked on cleanup during and after maintenance. 49

w 6 3.1.9 Equipment Conc.aons. The inspector verified cperability of ~ selected safety equipment by in-plant checks cf valve position-ing, control of locked valves, power supply availability and breaker positioning. Mlected major components were visually inspected for leakage, aroper lubrication, cooling water supply, operating air supply, and general conditions. Selected Emergency Service Water System valves and safety instrument root valves were also checked. 3.2 Followuo on Events Occurrino Ourino the Inspection 3.2.1 Excessive Heatup Rate - Unit 3 January 24. On January 24, 1984, while startup of Unit 3 was in progres, a trainee working under the supervision of the licensed reactor opera.or was taking plant heatup data required by paragraph 4.6.A.1 of the Technical Speci-fications. The trainee made subtraction errors in determining the reactor coolant temperature changa over a 15 minute time interval. The error was not recognized by the gperator until an increase in the coolant temperature of over 100"F in an hour hadoccur5ed. Thetemperatureofthe'a'recirculationloopindi-cated 230 F at 9:15 a.m. and 332 F at 10:15 a.m., an increase of 1020F in one hour. The temperature of the 'B' recirculation loop indicated 2450F at 9:30 a.m. and 3360F at 10:30 a.m., an increase of 1110F ',n one hour. The temperature of the 'A' recirculation loop indicated a 1100F increase during the 9:30 - 10:30 a.m. - period. Exceeding the heatup rate is one of two such apparent vio-0 lations (278/84-03-01). Technical Specifications allqw a 100 F temperature change in any one hour. When the licensee discovered the excessive temperature change, the heatup rate was reduced and the heatup proceeded at a much slower rate. (See paragraph 3.2.2 for corrective action.) The inspector verified the actions taken by the licensee and will continue to follow the licensee's correc-tive action. The inspector asked whether the licensee had any guidelines for control of trainees on-shift. The licensee stated that he has a policy that the qualified individual is fully responsible for all shift duties. The degree of supervision and oversight of trainee actions is solely at the discretion of the cualified individual (except for duties designated as " licensed cuties" by 10 CFR 50 and 10 CFR 55). The inspector interviewed the training coordin-ator and reviewed the training schedule of the operator trainees to determine if the trainee had been instructed on plant heatups and cooldowns and specifically been instructed on surveillance test procedure ST9.12 Revision 5. December 15, 1981, Reactor Vessel Temperatures. It was detennined that heatup and cooldown instructions as well as instructions on completing ST9.12 are scheduled for later in the training program. 9

8. 1-7 j .l i 3.2.2 Excessive Heatup Rate, Unit 2, January 31. On January 31, 1984, while j Unit 2 was being started ut, another apparent violation occurred when j the heatup rate exceeded 100 F over a one hour period. The reactor 0 was critical at 4:38 a.m. Between 4:43 and 4:54 a.m., the operator withdrew control rods 38 notches. This caused a heatup of 47oF over a 15 minute time period (4:45 to 5:00 a.m.). At 5:05 a.m., the oper-ator inserted a control red 3 notches to decrease the heatup rate. 4 At 5:07 a.m., he inserted the control red full in (7 notches). Be-tween 5:10 and 5:16, the operator inserted additional control rods 22 j notches in attempting to decrease the heatup rate. The A & B recir-culation loop reactor coolant temperatures increased an additional 45oF between 5:00 and 5:15 a.m. The reactor coolant temperature, as indicated by the recirculation loop A & B recorder traces, increased l 1100F between 4:20 a.m. and 5:20 a.m. Technical Specification allows 0 a 100 F reactor coolant temperature change in any one hour. This is an apparent violation (277/84-03-01). After this event, the operators were instructed to be more careful in maintaining heatup rates within l the technical specification limits. They were also instructed to use diverse instrumentation as a means of checking heatup rate. The lic-i j ensee stated he plans to add a heatup curve on the chart recorder as 1 i an operator aid. In addition, ST9.12 will be required to be initated earlier in the startup. The licensee is perfoming an engineening evaluation of the effects of the heatup rate on the reactor vessel. The inspector verified the actions taken by the licensee and will con-I tinue to follow the licensee's corrective actions. The' inspector ex-amined the chart recorder traces of the event and the rod pull sequences } to reconstruct the event and verify the licensee descriptions. The i inspector reviewed vendor training materials and noted that the nega-tive temperature coefficient of reactivity for this event (near end-of-cycle) could be expected to be very small, markedly less than at i beginning of cycle. The inspector noted that licensee procedures do not provide guidance on how to establish the proper heatup rate j (e.g., expected amount of rod movement and power levels), and do not provide reminders on the (predictable) manner in which the temperature coefficient of reactivity varies with core life and temperature. i 3.2.3 Unplanned Cooldown with Slight Reactor Vessel Pressurization--Unit 3, i January 25. About 5:30 p.m., January 25, with the reactor about 1350F in Cold Shutdown, operators were shifting the condensate and feedwater I system from short path to long path recirculation. When the procedure I was perfomed, feedwater injection isolation valves, which were re-quired to be closed, were left open. As a result, an injection path to the reactor was established in addition to the recirculation path. i Reactor Water level rose rapidly from about 40 inches to about 110 inches. Reactor temperature dropped to about 1100F due to the injec-l tion of cold feedwater. At the same time, the reactor pressure rose i I

8 briefly (i.e., for about five minutes) to about 10 psig, because the one-inch reactor vessel head vent path was inadequate to maintain the vessel at atmosoheric pressure during such a rapid level transient. The nomal. vent path, the three-inch main steam line drain, was iso-lated due to previous maintenance. Technical Specification 3.6.A Themal and Pressurization Limits, and its associated temperature-pressure graph Figure 3.6.2, prohibit ratures be-reactor pressurization above atmospheric pressure at tempF is there-low 1200F. Pressurization to about 10 psig at about 110 fore an apparent violation (278/84-03-02). The inspector reviewed logs and recorder charts and discussed this The licensee stated that the event with licensee station management. causes appeared to be operator error (failure to follow the procedure) and weak supervisory control and communication during the evolution. The licensee plans appropriate retraining, counselling or disciplinary action. Further licensee evaluation of this event is in progress. The inspector recomended that the licensee also (1) review human factors aspects of the procedure involved, in that the procedure appears unclear with respect to positive verification of the process valves involved, and (2) review procedural guidance with respect to reactor vessel vent path selection. 3.2.4 Unit 3 Scram - February 9. About 6:06 p.m., February 9,.with the unit near full power, the 38 reactor feedpump tripped on high vibration. Recirculation pump and turbine runbacks occurred as designed, but the turbine runback failed to reset. Consequently, a reactor power to turbine load mismatch developed, resul. ting in a pressure spike and, thus, a high flux scram. After the scram, the remaining feedpumps No ECCS tripped on low vacuum due to loss of turbine sealing steam. setpoints were reached, but RCIC was used manually to assist in water level control. The inspector reviewed recorder traces and discussed this event with operators and supervisors. The licensee detemined that a relay in the turbine runback circuitry had failed. The lican-see replaced the relay, repaired the feedpump, and returned the unit to operation. i No violations were identified. 3.3 Loos and Records The inspector spot-checked logs and records for accuracy, completeness, abnor-mal conditions, significant operating changes and trends, required entries. operating and night order propriety.. correct equipment and lock-out status, confomance to Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed: Shift Supervision Log, Reactor l EngineeringLog(sampledforUnits2and3),ReactorOperatorsLog(Units l i

~ 9 2 and 3), CO Log Book and STA Log Book, Night Orcers (current entries), Radiation Work Penmits (RUPs), Maintenance Request Forms (sampling), Igni-tion Source Centrol Checklists (sampling), and Operation Work & Information Data, all January 13 - February 27, 1984 Control Foom logs were compared against Administrative Procedure A-7, Shift Operations. Frequent initialing of entries by licensed operators, shift supervision, and licensee onsite management constituted evidence of licen-see review. No unacceptable conditions were identified. 9 = 89

10 4 4. IE Bulletin Followup--IE Bulletin 84-01: Cracks in BWR Mark I Containment Vent Headers, Dateo February 3, 1984 }' The bulletin indicated that on February 3, a plant with a Mark I containment 0 around the vent reported a through-wall crack which appeared to be 360 4 header within the torus. Although no actions were required of plants not in cold shutdown, it was suggested that plant data on differential pressure between the wetwell and drywell be reviewed for anomalies that could be indicative of cracks. The licensee performed tests (ST12.6, Primary Con-4 tainment Drywell to Torus Bypass Area Test) for Unit 2 and Unit 3 on February 5-6, 1984 to verify that the direct leakage path between the dry-well atmosphere and the torus free air volume was within Technical Speciff-cation limits. The inspector reviewed the test results on February 6 and questioned the operators and test engineers about the tests. Both units had satisfactory tests with leakage approximately one-fourth of the limiting value. The inspector also reviewed bypass test results of 9/81 and 8/83 for i Unit 3 and 7/80 for Unit 2 to look for trends. None were found. On February 6. BWR Mark I owners and GE met with NRC. Although the crack was concluded to be due to non-generic problems with the nitrogen inerting system, a GE Service Infomation Letter (SIL) was issued. The inspector verified that the licensee had received the SIL and was reviewing its recom-mendations. While Unit 2 was shutdown for MSIV LLRT, the licensee inspected the vent header inside the torus and, on February 20, found a defect that resulted from installation of stiffeners during torus mods perfomed in 1982. The defect was repaired (see below). Unit 3 has been at power and no inspec-tions could be done on the inside of the torus. The inspector will review Unit 3 findings when they are available (278/84-03-05). The defect found in the Unit 2 vent header was a damaged area behind a support plate for a stiffener at the vent header to downcomer intersection. Stiffeners had been added at each such location (144 total), as part of the BWR Mark I contain-ment long-term program, during the Spring 1982 refueling outage. The damaged area was abcut three-eighths inches by 5 inches, but had been partially l repaired, such that a three-eighths inch by three-quarter inch through-wall i hole remained. The hole was behind the stiffener support plate, with the defect lying near, and parallel to, the lower fillet weld attaching the 7 three-quarter inch thick support plate to the one-quarter inch thick vent header. The defect was visible only from inside the header. The licensee believes that the support plate was originally mispositioned and a weld started, then the plate removed (ground-out or " arc-gouged"), damaging the header), and finally the spport plate welded into the proper position. i The licensee reviewed the contractor's (Chicago Bridge and Iron) Nonconfom-i ance Control Lists and Repair Checklists and found that no nonconfomances or field repairs were documented for this support plate. Per the ASME code, examinations following support plate installation had been surface inspec-tions from the outside. Thus, the unreported defect was not identified until l a walk-through inspection by station engineers on February 20, 1984, i l The torus modifications were perfomed under contract with Bechtel, who sub-l contracted Chicago Bridge and Iron (CB&I) to do the in-plant work. The licensee's Engineering Work Letter (dated July 9, 1981, as well as subsequent l l

17 .~ revisions thereto) and Construction Job Memorandum (dated October 8, 1981, as well as subsequent revisions thereto) specified that the work (1) meet Section III of the ASME Boiler and Pressure Vessel Code,1977 Edition including Addenda through Summer, 1978, and (2) be performed under the CEaI The governing CBSI QA document, as approved by QA program and procedures. the licensee, was CBI Nuclear QA Manual for ASME Section III Products. Issue 8, March 22, 1978. Both the existence of a through-wall defect and the failure to formally control and volumetrically inspect the repair are 10CFR50 Appendix B Critarion XVI, Cor-nonconformances with the ASME Code. rection Action, as well as Section 2.16 of the licensee's approved Quality Assurance Plan (Revision 4 January 1980, and subsequent revisions) requires measures to assure that conditions adverse to quality are promptly identified and corrected. CBI Nuclear QA Manual for ASME Section III Products. Issue 8 Division 4, Section 14.4, requires that all nonconformances March 22, 1978 except (1) surface irregularities that are eliminated by surface condition-ing, and (2) welded corrections to welds made during the course of deposi-If a tion, shall be reported, documented, and formally dispositioned. nonconformance is repaired, the repairs shall be per an approved repair Failure to follow these requirements for procedure or contract drawing. a torus vent header nonconfomance associated with torus modification work is an apparent Violation (277/84-03-02). The inspector stated that this event also reflects noncompliance with 10CFR50 Appendix B Criterion IX, Control of Special Processes, in that neither the process that caused the damage nor the infomal, partial repair were adequately controlled. The licensee repaired the damaged area and radiographed the repair prior to Also, the licensee visually inspected about 20 percent of the startup. inside of the vent header wall at the locations of externally welded attat:h-No additional defects were found. However, on February 22 the ments. inspector toured the vent header and noted small inside wall depressions at three locations. The most severe depression was about 5/16 inches by 1/4 When infomed, the licensee confimed inches and about 0.1 inches deep. these depressions, expanded the sample size to 100 percent (about 500 weld locations), and began an evaluathn. The licensee inspections revealed two additional depressions, less severe than the others. The licensee's engin-sering evaluation concluded that the depressions were caused by overheating the base metal during fillet welding of the support plates to the outside. The evaluation concluded that the depressions were not significant, but The same stated that confimatory analyses would be obtained from Bechtel. phenomenon was then observed on February 24--when a part of the support plate fillet weld was removed then restored during repair of the damaged area, These depressions were slight depressions were created on the inside wall.Pending completion of the less severe than the previously identified ones. vendor anal ses, the disposition of the depressions is considered confimato unresolved 277/84-03-03. 5. Surveillance Testing The inspector observed surveillance to verify that testing had been properly control room operators were knowledgeable approved by shift supervision, regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instru-mentation was calibrated, work was perfomed by qualified personnel, and test acceptance criteria were met. Parts of the following tests were observed:

r 12 . ST10.11, Revision 4, August 5,1983, Average Scram Times for 00YN/B Minimum Critical Power Ratio (MCPR) Requirements, for Unit 3 performed on January 27, 1984. Documentation of the following completed tests were reviewed: . ST20.021-1, Revision 0, February 15, 1984, MSIV LLRT, completed February 18, 1984 (Penetration N-7A); . ST20.021-1, Revision 0, February 15, 1984, MSIV LLRT, completed February 18, 1984 (Penetration N-7B); . ST20.021-1, Revision 0, February 15, 1984, MSIV LLRT, completed February 18, 1984 (Penetration N-7C); . ST20.021-1, Revision 0, February 15, 1984, MSIV LLRT, completed February 18, 1984 (Penetration N-70); . ST12.6-1, Revision 6 July 22, 1982, Primary Containment Drywell to Torus Bypass Area Test - Unit 2 only, completed on February 6,1984; and . ST12.6-2, Revision 5, July 22, 1982, Primary Containment Drywell to Torus Bypass Area Test - Unit 3 only, completed on February 6,1984. Also, Surveillance Test ST7.2.1.a. Detennination of Dose Equivalent JEi/sm I-131 in Primary Coolant, Revision 7, for Unit 2 was reviewed for the month of January. The licensee analyzed the following nuclides: I-131 I-132 I-133, I-134, and I-135 and computed dose equivalent I-131--that amount of I-131 which alone would produce the same thyroid dose as the quantity and isotopic mixture of I-132. I-133. I-134 and I-135 actually present. The Technical Specification Limit is 2.0 microcuries per gram. Increased sam-pling frequency is required above 0.02 microcuries per gram. A monthly Unit 2 sample on January 10, 1984 indicated 1.265 E-3 microcuries per gram. No unacceptable conditions were identified. 6. R,adiation Protection During this report period, the inspector examined work in progress in both units, including the following: a.- Health Physics (HPl controls b. Badging c. Protective clothing use d. Adherence to RWP requirements e. Surveys f. Handling of potentially contaminated equipment and materials More than 40 people observed met frisking requirements of Health Physics procedures. A sampling of high radiation doors was verified to be locked as required. No violations were identified.

f..

13 7. Physical Security The inspector spot-checked compliance with the accepted Security Plan and implementing procedures, including: operations of the CAS and SAS, over 20 spot-checks of vehicles onsite to verify proper control, observation of protected area access control and badging procedures on each shift, inspec-tion of physical barriers, checks on centrol of vital area access and escort procedures. No violations were identified. 8. Startup Testing - Unit 3 Cycle 6 The inspector reviewed completed documentation of selected pre-critical and post-critical startup tests for Unit 3, Cycle 6 to verify that detailed instructions were included, acceptance and cperability criteria ware in compliance with Technical Specifications and the FSAR, changes to proced-ures had been properly approved, actual test results were satisfactory, and tests had been properly documented and reviewed. The following tests were reviewed: -- ST12.10. Revision 1 July 26, 1982, Core Post-Alteration Verificaticn, completed June 23, 1983; -- ST10.7, Revision 8, January 3,1983. Scram Insertion Times, ccmpleted August 8, 1983. -- ST10.8, Revision 8 August 5,1981, Control Rod Withdrawal Test, completed September 1, 1983, to verify rod coupling, CRD operability, and reactor sub-criticality with any one rod withdrawn; -- ST3.8.3, Revision 3, July,1983 Shutdown Margin Test, completed September 3, 1983; -- ST3.9, Revision 3. July 11, 1983 Critical Eigen Value Comparison, com-plated September 3, 1983; -- ST3.4.1, Revision 16. September 26, 1983, LPRM Gain Calibration, completed October 16, and October 26, 1983; -- ST12.8, Revision 1. June 2,1981 Recirculation System Baseline Data, . completed October 25, 1983; -- ST13.30.2, Revision 2. January 11, 1982 Core Flow Calibration, completed October 28 and October 31, 1983; -- ST3.7-3, Revision 22. July 11, 1983, Reactor Anomalies, completed October 31, 1983; and -- RE-27. Revision 8 January 3,1983 Core Power Symetry and TIP Reproduc-tibility Test, completed November 9,1983. l P .O

r 14 ~ In reviewing ST10.8, Control Rod Withdrawal Test, the inspector noted that the test requires ST3.1.2, Source Range Monitor (SRM) Core Monitoring Test, to be perfomed as a pre-requisite. ST3.1.2 was completed as required on July 1, 1983. ST10.S was perfomed during a period of nearly five weeks, Part of ST10.8 uses SRMs to verify that neutron July 3 - August 4, 1983. count rate responds to rod movement but the core remains sub-critical with Althcugh periodic repetition of ST3.1.2 dur-any one rod fully withdrawn. ing the test is not required, the inspector questioned if it should be done as a matter of good engineering practice, since SRM cperability is important (ST3.1.2 is required weekly during core alterations, but nomal to the test. control rod movement, such as for ST10.8, is not a core alteraticr.) The licensee said this matter would be evaluated; the inspector will review the results of this evaluation (278/84-03 03 ). The inspector also reviewed the licensee's post-outage startup report, sub-mitted to NRC on January 31, 1984, to verify that the test results described therein were consistent with the actual test documents. No violations were identified. 9. Licensee Manacement Changes The licensee informed the inspector of the following management and organira-tional changes, effective January 30, 1984: -- J. J. Gallagher, former Manager, Electric production, is appointed Manager, Engineering and Research Department; -- The position of Manager, Electric Production is replaced by two new positions, (1) Manager, Nuclear Production, and (2) Manager, Fossil-Hydro Production. M. J. Cooney, former Superintendent of Nuclear Generation, is appointed Manager, Nuclear Production; -- W. T. Ullrich, fomer Superintendent of Nuclear Services, is appointed Superintendent of Nuclear Generation; -- W. C. Whitfield, fomer Superintendent, Maintenance Division, is appointed Assistant to the Manager, Nuclear Production; and -- R. H. Logue, former Engineer-in-Charge, Nuclear Section, Mechanical Engineering Division, is appointed Superintendent of Nuclear Services. The licensee believes these changes will strengthen his nuclear organization.

10. Review of Licensee Event Reports (LERs) 10.1 In-Office Review The inspector reviewed LERs submitted to NRC:RI to verify that the details were clearly reported, including the accuracy of the descrip-tion and corrective action adequacy. The inspector detemined whether further infomation was required, whether generic implications were The fol-j indicated, and whether the event warranted onsite followup.

i lowing LERs were reviewed: i l

( I' - .a 15 LER No./ LER Date/ Event Date Subject

3-83-18/3X-l' Excessive scram times for two control reds.

02/10/84 11/17/83 3-83-23/3L Torus level transmitter could not be cali-01/12/84 brated and was therefore replaced. Redundant 12/13/83 indicators were operable. 3-83-24/3L One sensor of the moisture monitoring system 01/18/84 failed. Hourly drywell sump monitoring was 12/19/83 initiated. The inspector verified that hourly monitoring was initiated and no abnormal leak-age trends existed. 2-83-28/3L Due to equipment failures, two (of four) 01/20/84 HPSW pumps were inoperable for 7 days. 12/23/83 Continued operation was pennissable for 30 days. Other containment cooling equipment was operable. 3-84-01 HPCI turbine exhaust rupture disc failed during 02/07/84 testing and was replaced. Redundant equipment 01/06/84 was operable. Cause of the event is under investigation. The HPCI exhaust line is being manually drained periodically to ensure no water accumulates. NRC inspection of this LER remains open.

Selected for on-site followup.

10.2 On-site Followup For LERs selected for onsite review (denoted by asterisks above), the inspector verified that appropriate corrective action was taken or responsibility assigned and that continued operation of the facility i was conducted in accordance with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59. l Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewed. l LER 3-83-18/3X-1. This report updated an LER of December 7,1983, which reported slow scramming of one control rod on November 17, 1983. After a subsequent scram on January 14, 1984, it was found that an additional ( control rod, 34-27, had scramed slowly on both November 17, 1983, and l January 14, 1984. As a result of these occurrences, the licensee took the following actions: i l l t e

F \\ 16 (1) The pilot air solenoid valves for each of the two control rod hydraulic control units (HCU) were sent to the NSSS vendor for exam-ination. A yellow varnish-like substance was found to have stuck the plunger in the " energized" position on one solenoid valve from each HCU. Both the licensee and the NSSS vendor determined, through chemi-cal analyses, that the substance was Loctite 242 adhesive / sealant, which was applied per NSSS vendor recomendations to the solenoid housing cap nut to prevent loosening. All 370 Unit 3 solenoid valves had been rebuilt during the last refueling outage to replace limited shelf-life parts. (2) Prior to Unit 3 startup, the licensee disassembled and inspected 40 additional solenoid valves. One of the 40 showed minute traces of a yellow substance, but apparently had not stuck. All scram solenoids were functionally tested prior to startup. (3) The licensee reviewed all scram time data available for the cur-rent cycle at each unit. This included reevaluation of the scram time recorder strip charts that are printed out after each scram. No other slow scraming rods were identified. In the case of the January 14 scram, operators had demanded a process computer scan of control rod positions shortly (i.e. within 30 seconds) after the scram. This scan indicated that, as of the scan time, rod 34-27 was the only one that had not moved. Since the automatic scram time recorders are capable of timing only 58 of the 185 rods during any one scram, the licensee instructed operators to demand control rod scans shortly after each scram, as was done on January 14, in the future. Also, the licensee determined that the failure to identify the slow scram of rod 34-27 during initial review of scram time data from November 17 was due to Rod 34-27 misinterpretation and inadequate review of the strip chart. was the first of 30 rods printed across one chart. The continuous line printed by the chart (indicative of the rod remaining at position 48 for the entire twelve second duration of the print-out) was mis-interpreted as an ordinate of the graph. The LER comitted to a revision of the test procedure, ST10.9, CRD Scram Insertion Timing, to include detailed instructions and sample chart traces for identifi-I cation of abnormal scram times. This inspector will review the pro-cedure when revised (278/84-03-04). (.4) The licensee tested the backup scram valves prior to startup. (A rod whose solenoid valve sticks will still scram, after a time delay of typically 25-45 seconds, if backup scram valves actuate as designed to depressurize the entire scram air header.) The back-up scram valves, which are not safety-grade, operated properly and de-pressurized the header in about 25 seconds in the test. (5) The licensee tested the scram function of each rod prior to startup and scram time tested each rod during power ascension. e O

17 (6) A licensee task force reviewed QA/QC controls on scram pilot valve This review, which included a l rebuild kits and replacement parts. visit to the vendor facilities, concluded that the problem with valve sticking did not originate in the vendor (ASCO) facilities or during NSSS vendor (GE) storage and reshipment of parts. (7) The licensee contacted the manufacturer of Loctite 242, who stated that Lactite 242 has a tendency to migrate. The licensee has suspended its use on scram pilot valves and is avaluating alternatives. The NSSS vendor is perfoming similar evaluations and attempting to determine if similar problems have occurred at other plants. (8) The licensee designed means of acoustically monitoring solenoid positions and implemented a weekly check for solenoid plunger drop-out This testing will be continued until the licensee during half-scrams. has obtained sufficient data to assure on-going system reliability. (9) The licensee participated in development of an INPO Significant Event Report, planned for issuance in early March 1984. The inspector verified selected licer.see actions through review of completed tests, observation of in-progress scram time testing, inter-views of personnel, and examination of disassembled solenoid valves. The inspector forwarded this issue to NRC Region I management for evaluation of generic aspects. ~ The inspector retiewed the Technical Specification requirements appl 1-cable to plant operation between November 17, 1983 and January 14, 1984, the time period during which rod 34-27 had an excessive scras time. Technical Specification (TS) 3.3.C.3 states that scram insertion time for 90 percent insartion of any operable control rod shall not exceed 7 seconds. TS3.3.A.2 requires any inoperable rods to be positioned such that TS3.3.A.1 is met. TS3.3.A.1 requires operability of suf-ficient control rods such that the core could be made sub-critical in the most reactive condition during the operating cycle with the strong-est control rod fully withdrawn and all other o>erable rods fully Because the review of data from the (ovember 17 scram failed inserted. to identify the slow scram time of rod 34-27, the licensee subsequently operated the plant with rod 34-27 fully withdrawn and considered it (278/84-03-06)pparent Violation of Technical Specification 3.3 operable, in a was not positioned such that shutdown margin requirements were assured; thus TS3.3.A.1 and 3.3.A.2 were also apparently violated in this event. Rod 34-27 is a relatively high worth rod located near the center of the Had its excessive scram time been known, appropriate action during core. plant operation would have been either (1) to fully insert the rod un-til repaired, or (2) to perfom detailed, worst-case shutdown margin analyses if operation with the rod not fully inserted was desired. j i i l

/ 18

11. Committee Activities The inspector reviewed Plant Operations Review Ccemittee (PCRC) meeting minutes for 1983 to verify that proposed Technical Specification Amendments had received prior PORC review as required by Technical Specificaticns.

Proposed amendments had been reviewed in each case, and the reviews were documented in the minutes. In several cases, however, the information had not been cross-referenced to the licensee's PORC index system. This ham-pered retrieval and audit of the information. This matter was discussed with the licensee. 12. In-Office Review of Monthly Operating Report Peach Bottom Atomic Power Station Monthly Operatino Report for January 1984 dated February 10, 1984, as reouired by Technical Specifications was reviewed to determine that operation statistics had been accurately reported and that narrative summaries of the month's operating experience were contained therein. No violations were identified.

13. Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable, violations or deviations. An un,

resolved item is discussed in Detail 4. 14. Inspector Follow Items Inspector follow items are items for which the current inspection findings are acceptable, but due to on-going licensee work or special inspector interest in an area, are specifically noted for future follow-up. Follow-up is at the discretion of the inspector and regional management. Inspector follow items are discussed in Details 4, 8 and 10.

15. Management Meetings 15.1 Preliminary Inspection Findings A verbal sumr.ary of preliminary findings was provided to the Station Superintendent at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No draft inspection report material was provided to the licensee during the inspection.

15.2 Attendance at Management Meetings Conducted by Region-Based Inspectors l The resident inspectors attended entrance and exit interviews by region-based inspectors as follows: 1 i I AS e --.-a

f-l 19 Inspection Reporting Date Sdbject Pecort flo. Inspector January 25 (Entrance) Mark I Torus 277/84-04 L. Narrow January 27 (Exit) Modifications 278/84-04 January 17 (Entrance) Modificaticn 277/84-02 P. K. Eapen January 20 (Exit) Control 278/84-02 a 9 e ) = 4 60

m UNITED STATES .'p 6I f *.- c ? j NUCLEAR REGULATORY COMMISSION 7., y ) WASHINGTON, D. C. 20555 %, -:s ] JLEl181l184 MEMORANDUM FOR: Themis P. Speis, Director Division of Safety Technology Richard H. Vollmer, Director Division of Engineering Roger J. Mattson, Director Division of Systems Integration Hugh L. Thompson, Director Division of Human Factors Safety FROM: Darrell G. Eisenhut, Director Division of Licensing

SUBJECT:

AE00 ENGINEERING EVALUATION E414, " STUCK OPEN ISOLATION CHECK VALVE ON THE RESIDUAL HEAT REMOVAL SYSTEM AT HATCH UNIT 2" AE00 has submitted the subject Engineering Evaluation for our information and Due to a maintenance error an isolation check valve on a 24-inch use. injection line of the residual heat removal system was held open by its air actuator for a four month period. Inadequate post-maintenance test,ing and subsequent surveillance checks allowed the check valve to remain in the open position. The open check valve substantially degraded the isolation barriers between the high pressure reactor coolant system and the low pressure RHR system. Complete reliance was placed on the normally closed motor operated injection valve. AE00 concludes that a series of human errors led to this situation. Their cover letter recomends that the Integrated Maintenance Task Force of DHFS review the lessons learned from this event. Any questions or coments on the enclosed Engineering Evaluation should be directed to AE00. ^ f d ctor Division of Licensing

Enclosure:

As stated cc: W. Russell

0. Parr B. Sheron H. Bocher 6

P. Lam, AE0D q 4x d ( 1 se t ~ \\ ? \\

f' 't, g UNITED STATES 1. 3 's y,,i g NUCLEAR REGULATORY COMMISSION j WASHINGTON. D. C. 20555 / gs '---, ...../ g. y .vN '1 384 MEMORANDUM FOR: Harold R. Denton, Director Office of Nuclear Reactor Regulation FROM: C. J. Heltemes, Jr., Director Office for Analysis and Evaluation of Operational Data

SUBJECT:

STUCK OpEN ISOLATION CHECK VALVE ON THE RESIDUAL HEAT REMOVAL SYSTEM AT HATCH UNIT 2 Enclosed please find a recently completed Engineering Evaluation Report on the above subject for your infomation. The event is judged to have safety-significance because the open check valve substantially degraded the isolation barriers between the high-pressure reactor coolant system and the low-pressure residual heat removal system. This in turn led to a significant increase in reactor accident risks at Hatch Unit 2 because the mispositioned valve significantly increased the probability of an interfacing loss-of-coolant accident. Such an accident.which in this situation would be caused by a single failure of the nomally closed motor-operated injection valve,would involve the sudden discharge of high-pressure reactor coolant outside the primary containment and would also likely disable the low-pressure residual heat removal system. Our evaluation detemined that the stuck open isolation check valve on the low pressure coolant injection line at Hatch Unit 2 was caused by a series of human errors. They involved a maintenance error on the air actuator of the valve, inadequate post-maintenance testing, and inadequate surveillance of control room indications related to valve disk position and actuator travel. We believe that the lessons learned from this event regarding such human errors related to maintenance and post-maintenance testing of the isolation check valve would be of interest to the Integrated Maintenance Task Group within your office. P A \\ CT' ,Q \\

JUh. T ;354 Harold R. Denton. By a separate memorandum, we are suggesting that the Office of Inspection f! and Enforcement prepare an information notice on this and a related event at Pilgrim. If you have questions or comments, please contact Peter Lam 'i (x24438) of my staff. C. J. Heltemes, Jr., Director Office for Analysis and Evaluation of Operational Data

Enclosure:

As stated cc w/o enclosure: R. C. DeYoung, IE N. T. Russell, NRR J. Sniezek, DEDROGR

pMig(o UNITED STATES

,g NUCLEAR REGULATORY COMMisslON f WASHINGTON, D. C. 20855 3 8 i i*C 8 % *o** * / MAY S 11964 i 1 AEOD/E414 i MEMORANDUM FOR: Karl V. Seyfrit, Chief Reactor Operations Analysis Branch, AE00 THRU: Stuart D. Rubin, Lead Engineer Reactor Systems 4 Reactor Operations Analysis Branch, AE00 FROM: Peter Lam, Systems Engineer Reactor Systems 4 Reactor Operations Analysis Branch, AEOD

SUBJECT:

STUCK OPEN ISOLATION CHECK VALVE ON THE RESIDUAL HEAT REMOYAL SYSTEM AT HATCH UNIT 2 Enclosed is an Engineering Evaluation Report for an event at Hatch 2 in which an isolation check valve on a 24-inch injection line of the residual heat removal' systen was held open by its air actuator for a four-month period of power operation. The principal'cause of the event was a maintenance error on the air actuator. Important secondary factors which allowed the error to remain undetected. were inadequate post-mainte' nance testing of the check valve and inadequate surveillance of indications in the control room pertaining to the valve position and actuator travel. Thhttudy concludes that the open check valve substantially degraded the isolation boundaries installed between the high-pressure reactor coolant l system and the low-pressure residual heat removal system during the four-month period. The mispositioned valve thereby resulted in a fignificant increase in plant risk during the period because it signi-ficantly increased the probabil'ity of an interfacing loss-of-coolant accident. Such an accident wuld involve the sudden discharge of high-pressure reactor coolant outside the primary containment and would also disable the low-pressure residual heat removal system. It is suggested that this event be considered for inclusion in a future issue of Power Reactor Events. In addition to the usual distribution, it is also suggested that the report be sent to the Integrated Maintenance Task Group within the Office of Nuclear Reactor Regulation for infonnation. Q 597

fr*AY 31 s4 Karl V. Seyfrit. In light of the potentially severe consequence of an interfacing loss-of-coolant accident and the important contribution of htnan errors to the degradation of high-pressure / low-pressure system boundaries, it is suggested that the Office of Inspection and Enforcement consider issuing an Infomation Notice on this and a related event at Pilgrim which is also briefly discussed in the evaluation. Finally, this evaluation proposes that an industry group, such as the Institute of Nuclear Power Operations, define good industry practice for disabling testable check valve air actuators and their associated position indications in instances when flow testing is perfomed in accordance with ASME Section XI. n rs eter Lam, Systems Engineer Reactor Systems 4 Reactor Operations Analysis Branch, AE00 l

Enclosure:

As stated ~ 9 e

==- ? O \\ e e M 9-. y---r- -,_--w, ,--.-- -+--- ,-c--, -.y

AEOD ENGINEERING EVALUATION REPORT

UNIT:

Edwin I. Hatch Unit 2 EE REPORT NO. AEOD/E414 3 DOCKET NO.: 50-366 DATE: May 31, 1984 l. LICENSEE: Georgia-Power Company EVALUATOR / CONTACT: P. Lam NSSS/AE: General Electric / Southern Company Services and Bechtel

SUBJECT:

STUCK OPEN ISOLATION CHECK VALVE ON THE RESIDUAL HEAT REMOVAL SYSTEM AT HATCH UNIT 2 EVENT DATE: October 28, 1983 i 4

SUMMARY

On October 28, 1983, the isolation check valve on a 24-inch low pressure coolant injection line of the residual heat removal system at Edwin I. Hatch Unit 2 was found open and could not be closed. An immediate investigation by the licensee detemined that the valve was being kept open by the attached air actuator. A subsequent investigation by the licensee detemined that the check valve had been held open by the air actuator for over four months. During this period, the plant had operated at substantial power levels. The principal cause for this event was a maintenance error on the air actuator involving the backward reconnection of the two air supply lines to the actuator. The pneumatic pressure reversal which resulted caused i the actuator to hold open the check valve. Inadequate post-maintenance testing of the valve was considered to be. an.important secondary factor - which allowed the initial error to go undetected. A lack of adequate surveillance of the valve and air actuator control room position tpdi-l cetions was considered to be a third contributing factor. i This event is judged to be significant in terms of reactor safety because thg,::open check valve substantially degraded the high-pressure / low-pressure isolation arrangements provided between the reactor coolant system and the low-pressure residual heat removal system. The inadvertently opened valve thereby significantly increased the likelihood of an interfacing loss-of-coolant accident during the four-month period. While studying the Hatch event, another event report was _found for the Pilgrm Nuclear Power Station in which a significant degradation in the high-pressure / low-pressure isolation arrangements for the high pressure coolant injection system occurred. The cause of that event was also traced to multiple operator (hurnan) errors. l In light-of the potentially severe consequence of the Hatch event and the l significant contribution of hts:an errors to the degradation of the isolation barriers between the high-pressure reactor coolant system and low-pressure systems in both events, it is suggested that the Office of Inspection and Enforcement consider issuing an Infomation Notice for these occurrences. i It is also suggested that an industry group, such as the Institute of Nuclear Power Operations, consider evaluating what constitutes good industry practice and procedures for disabling testable check valve air actuators and their associated position indications when flow testing is perfomed in accordance with ASME Section XI. t t

This document supports ongoing AE00 and NRC activities and does not represent e

the position or requirements of the responsible NRC program office. 1 > cU - e n PM. ' \\\\QP

DISCUSSION 1. Event Description On October 28, 1983, with the plant in cold shutdown, personnel at Hatch Unit 2 discovered during valve operability testing that isolation check valve 2 Ell-F0508 on the residual heat removal (RHR) system "B" train was open and could not be closed (Ref.1). The valve was found being held open by its air actuator because its air supply lines were cosected back-wards. A subsequent investigation by plant personnel (Ref. 2) revealed that the check valve had been open since June 7, 1983. During this four-month interval the plant had operated at close to full power. Isolation valve 2 Ell-F050B is a swing-type testable check valve manufac-tured by the Rockwll International Company. It has an air actuator controlled by a four-way solenoid pilot valve manufactured by the Automatic Switch Company ( ASCO). The air actuator for check valve 2E11-F050B is of the rotary-type. The valve, its actuator and the solenoid valve are situated on the 24-inch low pressure coolant injection (LPCI) line inside the primary containment structure. The valve provides the first of two isolation boundaries between the high-pressure reactor coolant system (RCS) and the low-pressure RHR system. Upstream of the check valve and located immediately outside containment is a normally-closed motor-operated injection gate valve. The outboard valve opens automatically on an accident signal when pressure in the RCS falls'.below i the low pressure pemissive setpoint. The injection valve is the second and last isolation boundary between the RCS and the RHR system piping. l Thefgir actuator for the isolation check valve 2ET1-F050B is used by. the licensee (Georgia Power Company) to perfom inservice testing of the valve during cold shutdown. Prior to a test opening via the air actuator, the bypass valve on the 1-inch line around the check valve is opened to equalize the pressure on both sides of the disk of the 24-inch check valve. When the remote test push button is depressed, power is supplied to the solenoid pilot valve causing the pilot valve to shift. This in turn causes the actuator rod to rotate from its neutral position. When the actuator rod reaches its 150-degree position, it engages the check valve disk via a disk pin. Further rotation of the actuator rod lifts the disk from the valve seat. The actuator rod will rotate another 30 degrees to its 180-degree position where it will stop. The limit switch on the actuator gives an indication of actuator travel (the full 180 degrees from neutral) via a light on the control panel in the control room. A proximity switch tripped by a ferrous cam connected to the valve disk gives an indication of disk position (open) via another light on a control panel in the control room. The isolation check valve which provides the first of two isolation boundaries between the RCS and the RHR system is a safety-related component, while its air actuator and the pilot solenoid valve are not classified as safety-related. i ~.--.-....,-,,--,-....-.,._,,_,._n-. ,.n.,...-

On June 7,1983, at the end of a maintenance activity to repair an air leak on the check valve air actuator, the two air supply lines to the actuator were reconnected backwards. That is, the supply line which should have been connected to the right-hand cylinder of the actuator was incorrectly connected to the left-hand cylinder, and vice versa. This error was primarily attributed to the failure to use the check valve maintenance manual which was not available during the repair work (Ref. 3). Without the manual, maintenance personnel installed the two air supply lines to the actuator backwards. The two air suppy lines should have been arranged to physically cross each other on their way from the solenoid valve to the actuator cylinders. Instead they were routed to go straight to the actuator. The installation error caused the check valve actuator (rod) to move to the 180-degree position when air supply pressure was restored to the de-energized solenoid pilot valve. This action opened the check valve. The error was not discovered by post-maintenance testing even though such testing was recognized by the licensee as a requirement for return-ing safety-related valves to service. This requirement is stated in ASME Section XI, IWV-3000. In the ensuing four months, during which the reactor was operating at substantial power levels, the open check valve went undetected by plant operating personnel even though valve position and actuator travel indications were provided in the control room. l 2. Licensee Corrective Actions The immediate corrective action taken by the licensee following the discovery of the maintenance error was to correctly reconnect the air supply lines to the check valve air actuator. This placed the valve inHts correct nomal position (i.e., closed). A subsequent licensee action was to counsel the involved plant personnel on the importance l of performing equipment maintenance correctly. Specifically, plant i personnel were reminded of the need to perfom maintenance according to tli,e valve maintenance manual and to perform thorough post-maintenance testin before returning a valve to service. For the long tem, the licensee is considering adopting an alternative testing method for the LPCI isolation check valves (Ref. 4). This alternative test method, which is in accordance with ASME Section XI, IWV-3520 (Ref. 5), allows inservice testing of the isolation check valves to be perfomed by passing shutdown cooling flow through the valve during each cold shutdown. 3. Safety Significance This event is judged to be significant because the open isolation check valve substantially reduced the safety margins for preventing an interfacing Toss-of-coolant accident (interfacing LOCA) involving the RCS and the RHR systems during the four-month period that the valve was open. The isolation check valve on the 24-inch RHR injection line provides the first barrier to protect the low-pressure RHR system from an interfacing LOCA involving the - ~ ~. + w--.--.-+.-,,.,...,.,~.-ywwwrw,3,,, ,w , e n-,,.,..y,.,,,. ---.w,,.,---_

-4 RCS (Ref. 6). The second isolation device on the 24-inch LPCI injection line is the nomally closed motor-operated outboard gate valve. This gate (injection) valve is designed to open on a LPCI injection signal (i.e., low-low-low vessel water level or the combination of high containment pressure and low vessel pressure) when pressure in the RCS drops to the low pressure pemissive setpoint. There is no additional regulatory requirement other than independent diverse interlocks to prevent the gate valve from opening at full differential (reactor) pressure across the disk. Therefore, there is no assurance that the gate valve will not open aga'.1st full reactor pressure if the independent diverse interlocks fail. Thus, with the isolation check valye open, a postulated failure inyolving _ the motor-operated infection valve (e.g., spurious actuation or disk rupture) could allow the discharge of high-pressure reactor coolant into the low-pressure RHR system. The LPCI system is designed for operation in the 450 psig range. It is not designed to withstand the pressure or the dynamic loadings from the discharge of reactor coolant at operating pressure of approximately 1100 psig. Thus high-pressure reactor coolant could fail the low-pressure RHR system t piping or lift its pressure relief valves. Such an interfacing LOCA would likely disable at least one train of the RHR system and would certainly bypass the containment. Since the check valve was being held open by its actuator, its reclosure is not certain for several reasons. First, there are uncertainties in the extent of actuator interference, and in the flow conditions associated with a su~dden discharge of reactor coolant. For exampie, the total flow which would pass through the RHR system relief valve might not result in sufficieno differential pressure across the check valve to force its closure. Secondly, if suddenly forced to reclose in response to a very large rupture in the RHR system piping, the valve disk may not survive the dynamic loadings from such a rapid closure. Finally, a check valve held open by its air actuator for a prolonged period of timii"may increase the likelihood that the check valve will be stuck open from causes not related to the actuator interference which can be, for example, corrosion of the hinge pin or loose part obstruction. The probability of an interfacing LOCA associated with this event is estimated in Appendix A. There, the probability of a single failure of the motor-operated LPCI injection valve caused by a spurious actuation or a disk rupture was assessed using generic failure data. The extent of credit that could be taken for the held-open check valve to reclose was also discussed. The results indicate that the probability of an interfacing LOCA during a four-month period when a check valve is held open is significantly higher (from one to several orders of magnitude) than that associated with a nomally closed check valve. It should be emphasized here that the probability estimates in this evaluation are not intended to give a precise quantification of the likelihood of occurrence of the postulated accident or its associated risks.

Instead, they are made to underscore the safety significance of the event and to provide a risk perspective in the discussion.

+ _______..______-____.-___________._,__._.__m-_..

A further evaluation of many complex and interrelated events would be required to detemine how the accient might actually progress. For example, some of these events are: the availability of the renaining LPCI train and the success criteria for reflooding the core with only two LPCI pumps and the core spray system; the role and adequacy of other means of coolant makeup; the rate of depletion of supression pool inventory; and the extent of adverse environmental impact on vital equipment in the reactor building. An in-depth evaluation of these events is beyond the scope of this report. In any case, regardless of the specific scenario postulated, a blowdown of the reactor coolant system through a 24-inch line into the reactor building at nomal operating pressure and temperature would be a serious accident beyond the current plant licensing basis. 4. Occurrence of Similar Events The potential for a similar event occurring at other boiling water reactors (BWRs), was also assessed. The investigation first determined if other BWRs have similar RCS-RHR system interface configurations to that of Hatch Unit 2. The results of a recently completed study (Ref. 7) by Oak Ridge National Laboratory of light water reactor safety systems were examined. The Oak Ridge study reveals that a large number of BWRs have a similar RCS-RHR system interface configuration to that of Hatch Unit 2 (i.e., an inboard air-operated isolation check valve and a nomally closed outboard motor-operated injection val ve). The plants found with this configuration include Duane Arnold, Brunswiek 1 and 2, Cooper, Dresden 2 and 3, Hatch 1, Fitzpatrick, Monticello, Peach Bottom 2 and 3, Pilgrim, and Quad Cities 1 and 2. The next step taken in this evaluation was to investigate whether a similar i event had occurred at another BWR (i.e., a LPCI isolation check valve that was held open by its air actuator during power operations). A limited survey of ilWR Licensee Event Reports using the Sequence Coding and Search System (RET. 8) was conducted. The results indicate that a similar incident had not previously been reported at another BWR in the past two years. Therefore, i although a potential may exist for a similar event at other BWR plants, it i.s. apparently not a frequent event. A somewhat related event had occurred at Pilgrim on September 29, 1983. This event involved an actual overpressurization of the low pressure pump suction piping of the high pressure coolant injection (HPCI) system during a functional test of the HPCI system lo was also traced to personnel errors. gic. The cause of of the Pilgrim event The errors consisted of conducting more l than one surveillance test at the same time and not ensuring that test prerequi-sites and initial test conditions for all steps in the test procedure were i being met. The personnel errors led to the simultaneous opening of two HPCI pump discharge valves. With both valves open, a partially stuck open downstream testable isolation check valve pemitted a sudden pressurization of the low pressure HPCI pump suction piping. This event is similar to the Hatch 2 event in that it also involved the degradation of the high-pressure / low-pressure system isolation valves due to personnel errors. t --

FINDINGS The following findings were obtained in this evaluation: The isolation check valve on the RHR system at Hatch 2 was held open by 1. its air actuator for four months. During this four-month interval, the plant had operated at close to full power levels. 2. The occurrence was traced to a series of haan errors. The primary cause was a maintenance error consisting of a backward installation of the air supply lines to the attached air actuator. A secondary factor was the failure to discover the mispositioned valve due to inadequate post-maintenance valve testing. A tertiary factor was the lack of adequate surveillance of the control room indications for the air actuator and valve disk positions for the four-month interval when the valve disk was mispositioned. This event involved a significant reduction in the reactor safety margins 3. because the open check valve substantially degraded the RCS-RHR system isolation barriers. This in turn led to a significant increase in the probability of an interfacing LOCA during the four-month period of power operation. 4. A large number of BWRs have a similar RCS-RHR system isolation configuration to that in Hatch 2. These plants incorporate a normally closed (testable) air-actuated inboard isolation check valve and a nomally closed outboard injection gate valve on the LPCI injection line. Therefore, these plants may be susceptible to a similar occurrence if the air operator is not disabled during nomal power operation. 5. The event at Hatch 2 appears to be unique. An open LPCI testable check i valye has not been reported at other p1 ants in the past tw years. A calated event occurred at the Pilgrim plant which involved the degradation of the RCS-HPCI system isolation barriers. This event was also caused by a . series of personnel errors. i SUGGESTED ACTIONS In light of the severe consequence of an interfacing LOCA and the dominant contribution of huan errors to the degradation of the isolation barriers between the high-pressure RCS and the interfacing low-pressure systems, the followi'ng suggestions are provided: 1. It is suggested that the Office of Inspection and Enforcement (IE) consider issuing an IE Information Notice to all BWR licensees for this event and another event at Pilgrim involving the degradation of high-pressure / low-pressure system boundaries due to human errors. It is suggested that emphasis be placed on reminding licensees of the potential for isolation check valves to malfunction when the air actuators remain installed and enabled. The information notice should also remind licensees of the important contribution of haan errors to the loss of high-pressure / low-pressure system isolation features. e e _e---+m e,,e,----,,----,mi,ww.--ww,---,-,--yww--w- --- e e, .+------e -m

7-2. It is suggested that an industry group such as the Institute of Nuclear Power Operations or the BWR Owners Group consider defining good practice with regard to deactivating the air actuators of testable isolation check valves if and when the alternative inservice inspection testing is adopted. This alternative is the flow testing of the check valves during cold shutdown according to ASME Section XI, IWV-3520. If this alternative of flow testing is adopted, the air-operated actuator of the testable check valve could be deactivated in a way so as not to pose any mechanical interference with the operability of the check valve either in lifting on demand or in providing isolation protection. It would appear to be desirable to retain the position indication of the check valve in the control room even if the valve actuator is disabled for example, since isolation valve position indication plays an important role in preventing the occurrence of an interfacing LOCA involving the high-pressure RCS and the interfacing low-pressure systems. It allows early detection of check valve failures. Possible approaches are described in Appendix B. I .g. ? s i l I i 4 ,m----. y,--. .m.. -,, - - --,--v.

.~ REFERENCES 1. Licensee Event Report 83-112/03L-0, Hatch Unit 2, Docket 50-366, ~ Novenber 11, 1983. 2. Inspection Report 50-366/83-38, U.S. Nuclear Regulatory Commission, Region II, January 9, 1984. " Instruction Book for Testable Check Valves," Rockwell International, 3. S.0. 36-61247, March 8,1974. 4. Letter from J. T. Beckham, Jr., Georgia Power Company, to H. Denton, Director, NRR, U.S. Nuclear Regulatory Commission, " Inservice Testing of RHR LPCI Check Valves," April 30, 1982. I 5. " Rules for Inservice Inspection of Nuclear Power Plant Components," ASME Boiler and Pressure Vessel Code, Section XI, July 1,1977. 6. " Regulatory Guide 1.139, Guidance for Residual Heat Removal," U.S. I Nuclear Regulatory Commission, May,1978. 7. Fred A. Heddleson, " Summary Report on a Survey of Light-Water Reactor Safety Systens," NUREG/CR-2069, April,1983. 8. " Development of Licensee Event Report Sequence Coding and Search Procedure," NUREG/CR-1928, February,1981. 9. IEEE Std-500, " Guide to Collection and Presentation of Electrical, Electronic and Sensing Component, and Mechanical Equipment Reliability i i .; Data for Nuclear Power Stations," 1984. sm* 10. " Data Sanmaries of Licensee Event Reports of Valves at U.S. Commercial Nuclear Power Plants, Main Report, January 1,1976 to December 31, 1978," NUREG/CR-1363, Vol.1, June,1980. 11. " Reactor Safety Study - An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," NUREG-75/014 (WASH-1400), October,1975. 12. " Interim Reliability Evaluation Program: Analysis of the Browns Ferry, Unit 1, Nuclear Power Plant," NUREG/CR-2802, August,1982. 13. " Interim Reliability Evaluation Program: Analysis of the Millstone Point Unit 1, Nuclear Power Plant," Vol.1, NUREG/CR-3085, January,1983.

APPENDIX A A PRELIMINARY ASSESSMENT OF THE PROBABILITY OF AN INTERFACING LOCA The probability of an interfacing LOCA associated with the situation when the LPCI inboard check valve is held open by its actuator while the plant is operating at power (and pressure) is related to the single failure of the outboard motor-operated injection valve and the likelihood of the held open check valve failing to reclose. The single failure of the motor-operated LPCI injection valve refers to its inadvertent opening as a result of a spurious actuation or a disk rupture. The probability of such a single failure is estimated to be of the order of 2 x 10-" over the four-month pierod. This estimate is derived as follows. First, the rate of inadvertent opening of a normally closed, motor-operated valve due to spurious signals is of the order of 10 s per hour as assessed in IEEE Standard-500 (Ref. 9). The rate of disk rupture of a motor operated valve in a BWR is of the order of 10-7 per hour as determined in a recent study by EG&G, Idaho, Inc. (Ref.10), and in the Reactor Safety Study (Ref.11). These generic failure rates give a failure probability of the injection valve for a four-month interval of 2 x 10-" from (1.1 x 10 7/hr)(120 days)(24 hrs / day)(0.8), assuming a 80% capacity factor, f f little or no credit were taken for the held-open check valve to reclose-because of uncertainties regarding actuator interference, flow cond,itions associated with a sudden discharge of reactor coolant and the capabjlity of the check valve to withstand dynamic loadings, this probability of the motor-operated LPCI injection valve failing open would then be that of the interfacing LOCA. In this situation, the only barrier between the RCS and-2HR system is the motor-operated LPCI injection valve. A probability of approximately 2 x 10 " per a four-month interval (or 6 x 10 " per reactor year) as estimated above for an interfacing LOCA involving the RCS and RHR system would be higher by several orders of magnitude than those asfessed in comprehensive risk studies (Refs.11,12 and 13) which were approximately 10 ' per reactor year. If a great deal of credit were to be given to the successful reclosure of the held-open check valve even though its likelihood of occurrence i was judged uncertain, a value of the order of 10 l to 10 2 may be assigned to the failure probabil This in turn leads to a probabilit oftheordgrof2x10jtytoreclose.to 2 x 10

per a four-month interval (or 6 x 10 z to 6 x 10- per reactor year) for the occurrence of an interfacing LOCA.

l This value is still significantly mentioned risk studies (about 10., higher than those assessed in the afore-per reactor year). Thus, the event would appear to be significant because it involves a substantial reduction in the safety margins (i.e., a significant increase in risk) iri the prevention of a serious accident. l i 1 r----------,---,------ee,w+,-,p.,.~.-p.,w.w-------

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2-It should be noted that the probability estimates presented here are not intended to give a precise quantification of the likelihood of occurrence of the postulated accident or its associated risks. Instead, they are intended to focus attention on the safety significance of the event and to provide a risk perspective in the discussion in the main body of this report. 0 O 9 2 ? = D e e .-,.. - -. -,- - - - - - - - - - - -. -,.. -,. - - - - - -,--e

APPENDIX B DEACTIVATION OF AIR ACTUATOR It may be beneficial to plant safety to deactivate the air-operated actuator and at the same time retain the position indication capability if flow testing of the check valve according to ASME Section XI is adopted. This could be accomplished in any one of several ways. It could be accomplished by permanently capping the pressure line to the four-way solenoid valve. This would effectively disable the air-operated actuator regardless of the solenoid valve position since it would not receive any motive power to rotate the valve disk open. The power supply to the proximity switch for position indications would be -caintained. Another approach would be to disconnect the two air supply lines to the air-operated actuator. A third way would be to interrupt the power supply to the solenoid valve in a way which does not at the sane time cut off the power supply to the proximity switch. This is similar to the modification made to.an isolation check valve on the Pilgrim HPCI system to resolve an earlier concern regarding the potential of spurious opening of the check valve bypass line which predated the event referenced in this report. However, at Pilgrim the position indication for the check valve was not retained. 9 O 6 8 e

,M (3 '. cA CE:oq[o UNITED STATES [ g NUCLEAR REGULATORY COMMISSION q Q WASHINGTON, D. C. 20555 5 E 4..... j/ 1 m mss 4 Gentl emen:

Subject:

Draft Case Study Report - Steam Binding of Auxiliary Feedwater Pumps Operational experience shows that on a number of occasions an auxiliary feedwater ( AFW) pump was rendered inoperable due to steam binding resulting from backleakage of hot feedwater to the AFW systems. Backleakage occurs during nomal operation when the AFW system is not operating, but interfaces with an operating system at higher pressures and temperatures. The multiple valves, between the steam conversion system (main feedwater or steam generator) and the AFW system, leak pemitting hot water to enter the AFW system, flash to steam, and bind the pumps. The safety implication of the operating events is that backleakage represents a potential common cause failure for the AFW system that can cause the loss of its safety function. The AFW system is a safety system on a pressurized water reactor 1PWR) whose safety function is ~ to mitigate design basis accidents by providing a source of water for the steam generators when the main feedwater system is not available. Because of the safety implications of the events, AE00 performed a detailed case study of the backleakage events, the causes for valve leakage and the correctiv'e actions taken, and the generic safety significance of the events. A prelim-inary report of our investigation is enclosed. The purpose of this letter is to provide you with the opportunity to review the report, particularly with regard to its completeness and accuracy, prior to the issuance of the AE00 final report. Changes to the findings, conclusions, and recommendations will be considered if the underlying infomation concerning the details of plant design, systems operation, or event sequence is in Therefore, comments are being solicited on the technical accuracy of error. the report. The findings, conclusions, and recommendations are provided for your infomation in order that you understand the significance AE0D places on this event, and therefore, obtain a more complete picture of the total report. We would welcome your comments either infomally by phone or fomally by letter. Since we wish to finalize and issue the report shortly, we ask that any comments you may wish to make be brought to our attention within 30 days from receipt of this letter. As you may know, AE0D reports do not represent an of ficial NRC position or the position of the responsible NRC program office. Our reports are one input to an ongoing review and evaluation process, and any recommendation contained in ocr final report will be considered and perhaps modified or eliminated by the responsible NRC office. N A copy of the p,reliminary report and this letter are being placed in the Public Document Room at 1717 H Street, N.W., Washington, D.C. 20555. /as Wj % y ofi-a : D ug

i , o-a MAR 19 gy _g_ If you have any questions regarding this matter, please feel free to contact Wayne Lanning of my staff. Mr. Lanning can be reached at 301/492-4433. Sincerely, lbk C FHilt Wei, ,, Director Of e for Analy .; and Evaluation of Operational data

Enclosure:

As stated = 0 I ( l N i y k

w- 0 'O 4 Preliminary DRAFT l Case Study Report Steam Binding of Auxiliary Feedwater Pumps Reactor Operations Analysis Branch Office for Analysis and Evaluation of Operational Data March 1984 l 1 Prepared by: Wayne D. 1.anning I 1 l I l NOTE: This report documents the preliminary results of an ongoing study by l the Office for Analysis and Evaluation of Operational Data with I regard to a number of operating events. This report is issued for review and comment as part of the " peer review" process used for AE00 case studies. Since the study is ongoing, the content, findings, and recommendations are preliminary and may not represent the final position of AE00, the responsible program of fice or the Nuclear Regulatory Commission. i.(M

c- ~. 2 e e e TABLE OF CONTENTS PAGE ~ 1 EX EC UT IV E SU MMARY............................ 1

1.0 INTRODUCTION

4 2.0 AUXILIARY FEEDWATER SYSTEM DESCRIPTIONS.............. 5 2.1 We s ti ng ho u se De s i g n s..................... 6 2.2 Babcock and Wil cox Designs.................. 9 2.3 Combustion Engineering Designs................ 12 2.4 S umma ry o f AFW De s i g n s.................... 14 3.0 ANALYSIS OF BACKLEAKAGE EVENTS................... 15 3.1 Operational Experience.................... 15 3.2 Sa fe ty Si g n i fic anc e...................... 24 4.0 CAUSES FOR VALVE LEAKAGE...................... 28 S.0 LEAK DETECTION........................... 33 6.0 F I ND I NGS AN D CO NCL US I ONS....................... 36 7.0 RECOMMENDATION........................... 39

8.0 REFERENCES

41 FIGURES Figure 1 Schematic of H. B. Robinson Auxiliary Feedwater System. 8 Figure 2 Schematic of Crystal River Auxiliary Feedwater System. 11 Figure 3 Schematic of Calvert Cliffs Auxiliary Feedwater System. 13 TABLE Table 1 Summary of Operational Experience (Since 19 81 )........ 19 APPENDIX Appendix A Vapor Binding of Auxiliary Feedwater Pumps........ A-1 k )

a o EXECUTIVE

SUMMARY

A case study was completed to evaluate the generic safety implications of backleakage to the auxiliary feedwater ( AFW) system. Backleakage is defined as the leakage of hot main feedwater or steam from the steam conversion system to the AFW system. The AFW system is a safety system on a pressurized water reactor (PWR) whose safety function is to provide a source of water for the steam generators when the main feedwater system is not available and to mitigate design basis accidents. Operational experience has shown that on numerous occasions an AFW pump was rendered inoperable due to steam binding resulting from the leakage of hot feedwater to the AFW system. Multiple valves in series between the steam conversion system and the AFW system leaked and failed to provide isolation between the interfacing systems. The safety implication of these operating events was that backleakage represents a potential canmon cause faj1ure for the AFW system that can cause the loss of its safety function. Operating experience involving backleakage to the AFW system since 1981 included twenty-two events at six operating PWRs in the United States and one foreign plant. These events involved the misoperation or failure of about 60 check valves installed to prevent reverse leakage. Other plants were known to have experienced backleakage, but the events were not considered as reportable occurrences. The events at Surry Power Station Unit 2, H. B. Robinson Unit 2, and Joseph M. Farley Units 1 and 2, provided evidence that more than one AFW pump can be simultaneously adversely affected by back-leakage. The recent Surry event is the most significant eveat analyzed and is considered a precursor to a potentially serious accident scenario involving the loss of all feedwater. At Surry, the simultaneous steam binding of a E, pump in each train of the AFW system rendered the system incapable of perfonning its design function. The major findings of the study are: 1. The trend of the operating events involving backleakage to the AFW system increased sharply in 1983 when 13 of the 22 events occurred at five Westinghouse'-designed plants. 2. AE00's assessment of the safety significance of the events showed that (a) the loss of a single train due to steam binding is significant because it is presently an undetectable failure that jeopordizes the capability of the AFW system to meet single failure criterion and (b) the unavailability of the AFW system due to steam binding contributes signifi-cantly to risk of core melt in PWRs. 3. The potential for.backleakage into the AFW system is generic to all operating PWRs. The review of the AFW designs for the three PWR vendors found that check valves and remotely-operated valves in some designs isolate the AFW system from the steam conversion system. The AFW designs at Westinghouse-designed plants appeared more susceptible to backleakge and steam binding of the pumps because the remotely-operated valve is of ten nonnally open. Operating experience showed that backleakage occurred primarily at Westinghouse-designed plants. 4. The potential for common mode failure of the AFW system is present whenever one pump is steam bound because the pumps are connected by common piping (discharge header and/or recirculation piping) with only a single check valve to prevent backleakage of hot water to a second or third pump. 4

a -32 5. While a potential exists for backleakage to other safety systems in both PWRs and boiling water reactors (BWRs), there is no known report of steam binding of a pump in other safety systems. The standby safety systems are isolated from operating systems at higher pressures and tenperatures by check valves and motor-operated valves similar to the AFW systems. The potential for steam binding is minimized because the remotely operated valve is normally closed and is leak tested (the AFW valves are not). However, leakage through an upstream check valve has cause the remotely-operated valve to fail to open due to thermal binding and other reasons--a separate concern from steam binding. A previous AE00 study recommended measures to ensure the function of the valves which should address this concern. Since some BWR systems employ a smaller number of valves than were available in the AFW systems that experienced backleakage and steam binding of the pumps; a sephrate AE00 effort will further evaluate the safety significance of backleakage in BWR systems. 6. The analyses of the causes for check valve leakage did not identify any pattern or single major cause of the failures of the check valves. The causes differed between plants and involved different valve designs. 7. The study did not identify any regulatory requirements or uniform plant practices to reduce the likelihood of steam binding of the AFW pumps and common mode failure of the AFW system. AE00 recommends that the Office of Nuclear Reactor Regulation require PWR licensees to monitor the AFW system to detect backleakage and ensure that the fluid conditions within the AFW system are well below saturation conditions to prevent steam binding of the AFW pumps.

+.. AE00 suggested a possible method for further consideration that could reduce the likelihood of steam binding the AFW pumps and common mode failure of the AFW system. The method contains two basic elements: first, preventive measures to ensure that the isolation valves can perfom their intended function; and second, surveillances to ensure that the isolation function does not degrade during operations.

1.0 INTRODUCTION

Recurrent operational events at the H. B. Robinson Nuclear Power Plant involving automatic trips of the auxiliary feedwater ( AFW) pumps prompted AE00 to perform an engineering evaluation of the events. The pumps tripped due to a low pressure sensed in the discharge piping after the pumps were started automatically. The cause of the low pressure was attributed to steam binding of the pumps from leakage of main feedwater (MFW) into the AFW system (back-leakage). The hot MFW (about 425'F) leaked past two check valves and a closed motor-operated valve and flashed to steam in the lower pressure AFW system. Although the events involved only a single pump, the same phenomena had occurred in different AFW pumps at different times. Thus, a safety concern was raised that both trains could become steam bound simultaneously. The Engineering Evaluation (Ref.1) concluded that an Infomation Notice should be issued promptly to infom other licensees of the potential for the loss of AFW capability due to backleakage and steam fomation in the AFW system. The Office of Inspection and Enforcement issued the Infomation Notice on January 25, 1984. In the meantime, AE00 proceeded with a case study to evaluate the generic safety implications and to identify potential changes to technical specifications and inservice testing programs to detect leakage into the AFW system and prevent steam binding.

s This case study report documents the results of AE00's activities with regard to steam binding of the AFW pumps. Representative designs of AFW systems at operating PWRs are evaluated in Section 2. An evaluation of the operational experience dealing with reported backleakage events is contained in Section 3 followed by a discussion of the causes for valve leakage in Section 4. Requirements for leakage detection are addressed in Section 5. Section 6 presents the findings and conclusions developed from the analysis and evaluation of AFW steam binding phenomena which form the bases for the recommendations contained in Section 7. 2.0 AUXILIARY FEEDWATER SYSTEM DESCRIPTIONS This section summarizes the AFW system designs for operating Westinghouse, Babcock and Wilcox, and Combustion Engineering plants based on the AFW system descriptions compiled by the NRC Bulletins and Orders Task Force in NUREG-0560, NUREG-0611, and NUREG-0635, respectively. (Note that as a result o'f this and other post-TMI activities the designs of some AFW systems were changed or are undergoing changes. The descriptions contained in this section reflect the configuration of the AFW system at the time of this study.) The designs are reviewed to determine (1) whether the potential for backleakage exists during normal plant operation when the AFW system is not operating and (2) whether multiple pumps could be simultaneously affected. Thus, the focus of the review is to first highlight the number and kinds of valves that are used to isolate the AFW system from the steam conversion system (main feedwater and steam generators) and then identify common piping' between the AFW trains which could provide a flow path for MFW or steam that could lead to simultaneous steam binding of the AFW pumps. 5

2.1 Westinghouse Design The review of the AFW designs at Westinghouse operating plants found that the AFW and MFW systems are isolated either by multiple check valves in series because the remotely operated valve is normally open, or by multiple check valves and a nomally closed remotely-operated valve. Thirty of the operating plants use only check valves while only three plants (Robinson, Sequoyah, and j Turkey Point) employ the latter configuration for isolating the interfacing systems. Since Robinson experienced more backleakage events than other plants, its AFW system is described in this section. The primary differences between the plants that use only check valves to -isolate the interfacing systems is that in two plants the AFW system is connected directly to the steam generators via the MFW bypass piping rather than to the MFW piping as for the other 28 designs. These two plants (McGuire and Summer) empioy the Model D preheat steam generator design. A small feedwater flow rate is maintained in the bypass piping to prevent backleakage from the steam generator. However, even in these two designs the AFW and MFW systems also interface at another location that provides the same potential for backleakage as for other Westinghouse steam generator designs. A schematic of the AFW system for the H. B. Robinson Unit 2 plant is shown in Figure 1. The two motor-and one turbine-driven pumps share a common suction from the condensate storage tank. The two motor-driven pumps discharge to a common header before the flow is piped to each of the three steam generators. A single check valve exists between each pump and the header. A check valve and a normally closed. motor-operated valve exist in the piping between each steam generator and the common header. Thus, if the check valve and motor-operated valve leak in the pipe to either steam generator, only a single check is available to protect the pump from backleakage.

The turbine-driven AFW pump is connected to the MFW piping by a separate flow path via the MFW bypass piping. This piping contains only one check valve and a normally closed motor-operated valve for isolation. The discharge of all three pumps is connected by a common recirculation pipe to the condensate storage tank (see Figure 1). When the MFW leaks into,the AFW system, the water in the normally filled pipes is transferred to the condensate storage tank through the recirculation piping. A single check valve in the recirculation piping separates each of the pumps in the AFW system. Hence, in the event that a pump becomes steam bound, the recirculation piping provides a flow path for the hot water to the other pumps if the single check valve in the piping to each of the other pumps leaks. The seating force for the check valve is provided by the column of water from the valves to the condensate storage tank, which may not be effective in properly seating the valve to prevent backleakage because both sides of the check valve communicate with the condensate storage tank. The valve in the recirculation piping near the pump discharge opens each time the AFW pump operates. Operating the pump would augment proper seating of the check valves in the recirculation piping to the other pumps. But after the pump is shutdown, the differential pressure across the check valves may equalize, possibly unseating then. The McGuire and Summer plants have Westinghouse Model D preheat steam generators and separate AFW nozzles to the steam generator. For these plants, the AFW system is connected to the steam generator via the MFW bypass piping rather than to the MFW nozzle as is the case for other Westinghouse steam generator designs. A small feedwater flow rate is maintained in the bypass piping to prevent backleakage from the steam generator. However, the AFW system is

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still connected to the MFW piping at an upstream location. The pumps do not share a common discharge header in either plant design. There are two check valves between each AFW pump and the connection to the MFW piping and the remotely-operated valve is nonnally open. Both plants have temperature indicators on the MFW bypass piping near the auxiliary feedwater nozzle and downstream of the intersection of the AFW and MFW piping. The purpose of this instrumentation is to detect steam in the feedwater bypass piping to prevent water hammers in this piping, rather than to detect backleakage to the AFW pumps from the MFW system. The instrumentation is not capable of monitoring for backleakage to the pumps because of its location. In general, all AFW systems in Westinghouse operating plants have at least one check valve and a remotely-operated valve in series which can isolate an AFW train from the main feedwater system. However, the remotely-operated valve is normally open in most systems. As a result, only the check valve (s') provide the isolation function between the AFW and MFW systems. The flow control valve is nonnally closed in some plants, but this valve is not intended to be an isolation valve. In about two-thirds of the Westinghouse designs, at least two of the AFW pumps share a common discharge header with a single check valve between the header and a pump. For some plants, only the motor-driven pumps share a common discharge header; in other designs, all three pumps share a common header. A few designs have separate flow paths to the steam generators from each pump. Backleakage has occurred in each of the designs. For most AFW systems, all pumps share a common suction header from the condensate storage tank and are connected by the recirculation piping. 2.2 Babcock and Wilcox Designs l The review of the AFW designs at Babcock and Wilcox (B&W) operating plants found that the AFW system is connected only to the steam generator in all designs except i

for Crystal River which is connected to both the steam generators and the MFW system. Only Davis Besse and Arkansas Unit 1 employ nomally closed isolation valves in ~ addition to check valves to isolate the interfacing systems. The other B&W plants use only check valves to isolate the AFW system because the isolation valves are nomally open. The flow control valves are normally closed in two of the plants, but these are not intended for isolation purposes. All designs have a common pump discharge header except for Davis Besse and Crystal River. The recirculation piping and the piping from the condensate storage tank are common to all pumps in all designs. For discussion purposes, a diagram of the AFW system for Crystal River is shown in Figure 2. The pumps consist of a full-capacity turbine-driven pump and a full-capacity motor-driven pump. The piping arrangement is that either pump can deliver emergency feedwater to both steam generators. The piping is separated so that the pumps do not share a common discharge header, e.g., isolation valves exist between the pumps and the piping connection to the steam generators. The recirculation piping, however, is common to both pumps with two check valves available to prevent cross-flow between pumps. The AFW flow is through separate nozzles onto the steam generator tubes for B&W plants. As a result, the temination of the AFW discharge piping is in a steam environment. This design subjects.the AFW system to higher pressures and ^^ temperatures from the steam generator than other AFW designs. The Crystal River design also connects the AFW and MFW piping as !.hown in Figure 2. During normal operation, two check valves isolate the interfacing systems to prevent hot MFW from leaking into the AFW system, since the remotely-operated valves are nomally open. At Crystal River steam backicakage is prevented by the MFW flow through the piping to the steam generators.

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The other B&W designs do not interface with the MFW system. However, steam binding of the AFW pumps could result from the steam fonned in the system if the AFW is heated to saturation conditions by the leakage of steam from the steam generators. Backleakage to an AFW pump is p evented in these designs by two check valves in the Oconee and Rancho Saco plants (the motor a operated valves are nonnally.open) or_ a combination of at least two check valves and a normally closed mdtor-operated valve at the Davis Besse and Arkansas Unit 1 plants. The pumps in most designs share a common discharge header and recirculation pi ping. A single check valve is available to prevent backflow to the other pump if one pump becomes steam bound in all designs except for Crystal River f (discussed above) and Davis Besse. 'The latter plant does not have a common discharge header, but the recirculation piping connects both pumps with a check valve to protect each pump as is the case for other B&W plants. 2.3 Combustion Engineering Designs The designs of the AFW systems for Combustion Engineering (CE) plants differ between plants and there does not appear to be an AFW design that is typical for operating CE plants. A diagram of the Calvert Cliffs AFW system is shown in Figure 3 for reference. The AFW pumps usually consist of either a 100% capacity motor-and a steam-driven pump or one full-capacity turbine-driven and two half-capacity motor-driven pumps (Calvert Cliffs has two 100% capacity turbine-driven pumps and a 100% capacity motor-driven pump). Except for Arkansas Nuclear One, Unit 2, the other CE AFW designs employ a common discharge header for at least two pumps. The recirculation piping is common to all pumps with a single check valve to

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Row"D'esgEstors: $ otwemo. AFW hannsa-hrn se h Am Operstre i Wrw snusaa.n ~ M3 SchematioICitvert Chats AuxAsy Foeowst7Shm 1 , -. -,. - - - ~, en--e a

prevent backleakage from another pump. Typically, the AFW designs employ two check valves and one nonnally closed remotely-cperated valve to is'olate the AFW from the steam conversion system, except for Calvert Cliffs and Millstone, Unit 2, where the remotely-operated valves are partially open. The discharge of the AFW system is connected either directly to the steam generator downcomer by separate nozzles or to the MFW piping upstream of the main feedwater nozzle. For some of the plants that have the separate AFW nozzles, the AFW piping is also connected to the main feedwater piping. I 4 2.4 Summary of AFW Designs To summarize the review of the various AFW designs, most systems contain multiple check valves and at least one remotely-operated valve in series that can isolate the steam conversion and AFW systems. The primary diff,erence between the AFW designs for the three PWR vendors is that the remotely-operated valve (s) is normally open in Westinghouse plants (except Robinson, Sequoyah, and Turkey Point) and B&W plants (except for Davis Besse and Arkansas, Unit

1) and is nonnally closed in CE plants (except Calvert Cliffs and Millstone-2).

Hence, a majority of operating PWRs have only check valves to isolate the AFW and steam conversion system which could make them more susceptible to backleakage and steam binding of the AFW pumps than the plants which have a nonnally closed remotely-operated valve. The AFW pumps in most designs have common piping which increases the potential for steam binding of a second or third pump if any one pump becomes steam bound. The review of the AFW designs did not identify any available instrumentation to i ' monitor or detect backleakage from the steam conversion system.

. 3.0 ANALYSIS OF BACKLEAKAGE EVENTS Backleakage is defined as the leakage of feedwater or steam from the steam conversion system to the AFW system. This backleakage occurs while the AFW system is idle and the main feedwater system is operational. As discussed in the AFW system descriptions, check valves and, in some designs, renotely-operated valves isolate the AFW system from the steam conversion system. Because the MFW and steam generators are at a higher tenperature and pressure than the AFW system, the effect of backleakage on the AFW system is to increase the tenperature of the AFW fluid to saturation conditions that can result in steam in the system. Steam in the pump casing can cause pump cavitation and possible damage to the pump due to overspeed and vibration. The potential exists for steam binding of the redundant AFW pumps because the trains are cross-connected in most designs by a common dischar,ge header and/or by common recirculation piping. In order for a single pump to experience steam binding, it is relevant to note that leakage must occur through multiple valves in series. However, after one pump is exposed to steam in most plants, only a single check valve in connecting piping is usually available to prevent leakage and potential steam binding of another pump. 3.1 Operational Experience Since 1981 and more frequently in 1983, events involving backleakage were reported at H. B. Robinson (Refs. 2-5), D. C. Cook Unit 2 (Refs. 6-8), William B. McGuire Unit 1 (Ref. 9), Crystal River Unit 3 (Refs.10 and 11), Surry Power Station Unit 2 (Ref.12), and KRSK0 Nuclear Project (Yugoslavia, Ref. 13). Table 1 provides a tabulation of these events. The events at H. B. Robinson and D. C. Cook are described in Reference 1, which is enclosed in

Appendix A. The reader is referred to the Appendix for details of these events, particularly the events at Robinson. The event at the Surry Power Station, Unit 2, is the most significant operating event because it is considered a precursor to a potentially serious accident scenario involving the loss of all feedwater. While at power, one of the motor-driven pumps and the turbine-driven pump were simultaneously steam bound leaving only a one-half capacity motor-driven pump available. Thus, the AFW system was not capable of perfonning its design function, although one pump may be sufficient to remove decay heat (see Section 3.2). The system was inoperable pursuant to the technical specifications, and this event highlights the common cause failure potential of the AFW system due to backleakage and steam binding of the pumps. Backleakage had occurred previously, but it had affected only a single AFW train. Fortunately in the event of loss of all feedwater at Surry Unit 2, there is the capability for the AFW system at Unit 1 to supply emergency feedwater to Unit 2. The coincident failures of two AFW trains was the ide1tified concern resulting from the previous analyses of the Robinson events (see the Appendix). Separate trains had failed at different times at Robinson, but there was evidence that multiple pumps could be simultaneously affected. This led to the conclusion that the failures of single AFW trains should not only be considered as random failures, but also as contributing events leading to the potential common mode failure of the AFW system. The Surry event provides additional evidence to support this conclusion. It is noteworthy that backleakage in these events was detected indirectly and reported only because the AFW train was declared increrable. For example,

three events at Robinson involved an automatic trip of either a. motor-or steam-driven AFW pump due to low discharge pressure after an automatic start which caused the train to be declared inoperable. The events at Crystal River involved a single train of AFW system being declared inoperable because a flow sensor failed. The backleakage at D. C. Cook was detected during a rcutine operator tour by feeling the piping, but was reported only after the pump was isolated to work on the check valves. Backleakage from the steam generators at KRSK0 was identified after experiencing a severe waterhammer. The events at Surry were reported because a pump's oil cooler developed a leak which rendered the pump inoperable. At Crystal River, recurring failures of the ultrasonic AFW flow instrument were attributed to backleakage which increased the temperature of the AFW' piping and fluid and caused steam fonnation in the system which resulted in erratic indications and subsequent failure of the instrumentation. The train was declared inoperable. The pump was not thought to be affected by the leakage, although the pump casing was not checked after the event for or high temperatures indicative of backleakage. For this case, three additional check valves were available between the leaking check valve and the pump.

Thus, instrument readings and eventual failure provided an indirect indication of check valve leakage.

The events reported at the William B. McGuire (Ref.10) and H. B. Robinson (Ref.14) plants involved backleakage which caused the suction piping of the AFW system to be overpressurized. These events were caused by either the slow closing (McGuire) or improper seating of the discharge check valve (Robinson) which pennitted the MFW to pressurize the piping. Although these events l

V ' 7 involved gross backleakage, they represent anothe ' mode where the AFW pumps can ~ become steam bound.* Gross backleakage from the steam generators to the AFW pumps occurred at the KRSK0 plant in July 1981 during hot functional testing. KRSK0 is a two-loop Westinghouse plant with preheat (Type 0) steam generators (separate AFW nozzle to the steam generator). The significance of the event was that a severe waterhammer caused damage to the AFW piping and hangers associated with both steam generators. The damage was not discovered until several weeks after the incident was believed to have occurred. The main feedwater system was probably not in operation at the time (Ref.14). Based on the infomation available, the AFW pumps were started and stopped during the testing. It could not be ascertained whether the AFW pumps tripped or th,e intermittent starting and stopping of the pumps was perfomed by the operator. Two check valves in the piping to each motor-driven pump leaked while the pumps were idle between restarts, and was indicated by evidence of high temperatures (blistered or discolored paint) on the AFW piping back to the motor-driven AFW pumps. The turbine-driven pump is believed not to have been affected, although this train was not checked for leakage at the time of the event. The AFW pumps were not required to be operable because the event occurred during preoperational testing. As the result of the KRSK0 event, temperature instrumentation was installed on the MFW bypass piping near the steam generators at McGuire and Summer to detect and prevent waterhammer events similar to the one that occurred at KRSK0 because the steam generator design (Type 0) and AFW piping layout are AE00 had previously analyzed these events as they related to overpressuriza-tion in an Engineering Evaluation Report (Ref.15).

. ig. TABLE 1

SUMMARY

OF BACKLEAKAGE EVENTS (Since 1981) Plant Date No. of Valves Conments Leaking Cook-2 7/12/81 2 check Turbine-driven AFW pump (TDAFWP) valves (CV) casing was hot. Pump isolated and the train declared inoperable. Cook-2 10/29/81 2CV TDAFWP casing was hot. Pump isolated and the train declared inoperable. Cook-2 1/16/83 2CV TDAFWP casing was hot. Plant in operational mode not requiring pumps to be operable. Crystal River-3 12/20/82 1CV Train declared iroperable. Backleakage caused flow sensor to fail. Crystal River-3 10/03/83 1CV Train declared inoperable. Backleakage caused flow sensor to fail. Robinson-2 6/11/81 2CV and 1 Motor-driven AFW pump (MDAFWP) tripped motor-operated during plant startup.. valve (MOV) Robinson-2 6/16/81 2CV and MDAFWP tripped after reactor trip. 1 MOV Robinson-2 6/19/81 Unknown MDAFWP tripped on low discharge pressure after reactor trip. TDAFW out of service. Pump trip believed to be caused by improper discharge valve throttle setting. Same pump tripped on 6/16/81 due to steam binding. Robinson 5 4/19/83 2CV and MDAFWP tripped af ter reactor trip. 1 MOV Steam vented from pump casing. Robinson-2 4/20/83 4CV and Both MDAFWP casings were hot. The 2 M0V or leakage path for the hot water to 3CV and the second pump was not identified. 1 MOV Leakage to the second pump may have been through either the common dis-charge header or the recirculation piping through a single check valve. (See Figure 1). Robinson-2 7/21/83 1CV and TDAFWP casing was hot and steam vented 1 MOV from the casing. Train inoperable.

TABLE 1 (contd)

SUMMARY

OF BACKLEAKAGE EVENTS (Since 1981) Plant Date No. of Valves Comments Leaking Surry-2 11/18/83 4CV MDAFWP steam bound and failed to develop flow. Surry-2 11/20/83 8CF MDAFWP and TDAFWP steam bound AFW system was inoperable. Surry-2 12/06/83 4CV MDAFWP steam bound. Train declared inoperable. Farley-1/2 Ongoing 4-12CV MDAFWP and TDAFWP casings were since per unit hot, sometimes at the same time, mid-83* Pumps were run to reducetemperature. No pump declared inoperable by licensee. KRSK0 7/81 4CV Waterhammers occurred when AFWP started. Event occurred during pre-operational testing. (Pumps not required to be operable.) McGuire-1 8/25/81 2CV Slow closing of CVs caused the AFW pump suction piping to be overpressurized.

s.

i A minimum of six events are assumed to have occurred at both Farley units although each train has been affected more than one time since 1983.

similar. This instrumentation is not intended to detect leakage to the AFW pumps because the connection of the AFW and MFW piping is upsteam of the instrumentation. A small constant flow rate is also maintained in the bypass piping to prevent steam formation or backleakage in this small section of the AFW piping. The AFW and MFW systems are connected at an upstream location, providing a potential leakage path to the AFW system. A search of the operational data bases did not identify backleakage problems affecting AFW pumps at other operating plants. It could not be ascertained whether other plants had not experienced this problem or whether the problem existed, but was not identified as the root cause for the reported events involving inoperable AFW trains. For example, when H. B. Robinson experienced failures (LERs 79-32, 33 and 34) of the AFW pump discharge motor-operated valve to open, the initial causes were attributed to either the Limitorque operator or the inadvertent operation of the power supply breaker. The final evaluation of the valve failures concluded that thermal binding caused the valve to stick closed, which ultimately affected the interaction between the torque switch and valve internals. Backleakage was the reason identified for the thennal binding. Crystal River has also reported failures of the motor-operated valve to open, but the cause was attributed to other reasons, although backleakage is known to occur in the AFW system. H. B. Robinson had also reported AFW pump trips due to improper throttle valve settings. It is possible that backleakage may have caused the trip because the trip was initiated by the same low discharge pressure instrumentation that caused the pump trip when steam binding of the pump was positively identified. It should be noted that unless the backleakage results in an event which is otherwise reportable by the technical specifications, the fact that back-leakage occurred is not reportable. We have been told infonnally that

' other operating plants, in addition to D. C. Cook (Ref. 9), have experienced leakage of the AFW discharge valves. This leakage has occurred in both AFW trains several times and was never judged to be a reportable event. Both units of the Joseph M. Farley Nuclear Plant, for example, experienced significant backleakage in both trains of their AFW systems. The only event reported by the Farley plant (Ref.16) was the backleakage through the check valve closest to the motor-driven AFW pump at Unit 1. The AFW train was declared inoperable to repair the valve. No mention was made in the report that the three upstream valves had also leaked in order for this valve to leak and that the backleakage caused the relief valve on the AFW pump suction to lift. An operator during his routine rounds noticed that the relief valve was opening, and measured piping temperatures in excess of 200*F. Elevated piping temperatures had previously been detected in both AFW trains, sometimes simul taneously. Since the summer of 1983, both units of the Farley plant have experienced recurring events involving backleakage through check valves that were not reported. Presently, the AFW pumps at both units are run periodically to reduce the 'AFW fluid temperature. There have been numerous AFW check valve failures reported in Licensee Event Reports. The descriptions of the events address single valves and do not identify multiple ct"ck valve failures that could lead to steam binding of the AFW pumps. As a result, these events have not been included in this study. These events, particularly the failures of the check valves to close and separation of the disc from the disc ann, contribute to the potential for backleakage and ste.3 binding of the AFW pumps. In addition, there have been reported failures of the single check valve in the recirculation piping that could provide a path for steam or hot water to reach the other AFW pumps.

Operational experience shows that check valves, in general, have a history of leakage problems in all systems. Most plants consider check valve leakage as routine and expected. Operating experience shows that the check valves in the AFW system also fail open or leak. There are other systems in PWRs where the interface between operating systems at high temperatures and pressures are separated from standby systems by check valves and remotely-operated valves in series, e.g., the emergency core cooling system (ECCS). Thus, the potential also exists for backleakage to these systems. Although there are reports of these valves leaking, no event is known to involve steam binding of the pumps. The remotely-operated valve is normally closed which should minimize the potential for backleakage to the pump. Additionally, these valves are periodically leak tested (the AFW valves are not) to ensure their leak integrity (see Section 5).

However, the reverse leakage through the check valve can adversely affect the operability of the motor-operated valve as evident by the Robinson events (see Section 4).

An AE00 study (Ref.17) of valve operator-related events also found that check valve leakage can cause failure of the motor-operated valve to open when required. Thus, check valve leakage has other safety implications in addition to steam biriding of pumps. The potential also exists for backleakage from the MFW sy', tem to safety-related systems in boiling water reactors (BWRs). For example, a check valve and a ncnnally closed motor-operated valve isolate the high pressure coolant injection (HPCI) system from the MFW system. (Note that this represents a smaller number of valves than in the AFW systems that experienced backleakage.) This is also true for the Reactor Core Isolation Cooling (RCIC) system. Events have been reported at OWRs involving the backleakage from the MFW and reactor coolant

systems. This study did not attempt to evaluate the safety implications of backleakage. to these systems. However, a separate AE00 effort will review the operating experience and safety implications of backleakage in BWR systems. 3.2 Safety Significance The safety implications of backleakage of feedwater or steam to the AFW system is that it represents a potential conson cause failure that could render both trains of the AFW system inoperable. Some plants are more vulnerable than others depending on the piping configuration and layout, the number of pumps, the number and type of isolation valves, the normal operating position of the valves, and the maintenance and surveillance practices in effect. The events involving single AFW trains, particularly the recurring events at H. B. Robinson, should not only be considered random failures of single AFW trains, but as contributing events which portend the potentiaT loss of AFW capability due to a common cause failure. The loss of a single train by itself is significant because its failure may not be detected until it is required to operate which jeopordizes the capability of the AFW system to meet single failure criterion. Since 1981, the 22 events involving backleakage to the AFW system represent about 60 check valve failures to prevent leakage. In 1983, there were 14 events that rendered an AFW train inoperable (only six events were counted at Farley Units 1 and 2 although every pump was affected more than one time). Thirteen of these events occurred at operating Westinghouse plants. AE00 assessed the safety significance of the loss of the AFW system due to steam binding of the pumps using a risk-based approach. The accident sequence considered is the loss of the steam conversion system after a transient event other than loss of of fsite power. This sequence (TML) is a dominate contributor to risk based on a probabilistic risk assessment for

the Sequoyah plant and results in a category PWR-3 release (Ref.18). The faul t trees for the AFW system do not include steam binding as a separate failure mode for the AFW pumps. The loss of both the MFW and the AFW systems tenninates all feedwater flow to the steam generators. Without feedwater, the steam generator secondary side boils dry, resulting in the loss of the heat sink to remove energy from the reactor coolant system (RCS). The RCS pressure will increase, causing the safety and relief valves to open. The RCS inventory will be lost through the valves, which requires the operation of ECCS systems for makeup in order to avoid core uncovery and eventual core melt. For Westinghouse-designed plants, the steam generator dryout times range from approximately 13 to 40 minutes. In the event the AFW pumps are steam bodnd, the operator has only a short time to identify that this is the failure mode of the AFW system, to stop the pumps before pennanent damage occurs, and to restore their function in order to interrupt this sequence. Unless the operator immediately recognizes that the pumps are steam bound and recovery actions (which must be performed locally at the pumps and coordinated with the control room) are timely and successful, the likelihood of preventing steam generator dryout i s small. The probabilistic risk assessments for some plants show that successful AFW system operation requires the flow equivalent to one pump to one steam generator. Hence, the flow from a one-half capacity pump may be sufficient to prevent steam generator dryout. However, the expected increase in the reliability of the AFW system assuming successful operation with only one pump may be reduced by the potential common mode failure contribution in detennining the overall reliability of the system.

26 - Using a risk-based approach for detennining safety importance, the unavailability of an AFW system containing three pumps is calculated based on the operating experience for PWRs for 1983. First, the unavailability of one or more AFW -3 pumps due to steam binding is about 7x10 / demand (13 events at 47 operating plants each with 3 AFW pumps subject to 15 demands per reactor year (RY) based on 12 surveillance tests and three AFW challenges after reactor trips). Secondly, the i conditional failure probability for a second pump to fail due to steam binding is 0.23 (3 of the 13 events involved two pumps). For this calculation, a pump is considered to be steam bound when hot water is detected at the pump, i.e., the hot water flashes to steam when the pump starts and binds the pump. Two of the events involved this condition; the third event involved actual steam binding of two pumps. The probability of a third pump becoming steam bound is assumed to be i 0.1 based on the common cause dependency for the hardware between trains.having the same design and subject to the same environment. Combining t,he failure j probabilities for the three pumps, the unavailability of the AFW system is -4 about 1.5x10 / demand. For designs with two AFW pumps, the unavailability is increased by 50%. The unavailability of the AFW system for the Sequoyah plant without loss -5 of ac power (low unavailability for the onsite power) is about 4x10 per demand. Therefore, the core-melt probability considering the steam binding -6 l of the AFW pumps for the TML sequence is increased from 2.8x10 /RY to -5 1.1x10 /RY (an increase by a factor of four). This is obtained by adding the unavailability of the AFW system due to steam binding to the Sequoyah value and using the probabilities contained in the Sequoyah analysis for -2 transients (7/RY) and loss of the power conversion system (10 / demand). This increase doubles the contribution of the TML sequence to the probability of a category PWR-3 release, which is already the most probable release L

R, category at Sequoyah. For a PWR-3 release, this would represent a risk l l increase of about 45 man-rems /RY based on a dose calculation for a PWR and l l typical mid-western meteorology (NUREG/CR-2800). Using this technique, the estimated risk increase is about 60 thousand man-rems for the remaining lifetime of all operating PWRs (47 units with an average remaining life of 27 years). These estimates are based on known operating experience involving backleakage to the AFW system. As discussed previously, reported operating experience may not accurately reflect the number or frequency of steam binding events or the number of pumps that are affected, because backleakage is not by itself a reportable event. In addition, the reasons are not clear for the absence of steam binding events at Cf. and B&W operating plants since the AFW designs are very similar to the Westinghouse designs. Consequently, the small population of steam binding events are not sufficient to predict future occurrences with certainty, and the risk could be higher than indicated by the point estimates based on the reported operating experience. The lessons learned from the evaluation of the operating experience for reactor trip breakers after the Salen anticipated transient without scram ( ATWS) events should not be forgotten in assessing the significance of available operating experience for steam binding events. One of the important lessons was that routine statistical analyses of single failures and failure rate data cannot by itself predict potential common mode failures, even when a relatively large population exists as in the case of trip breakers, as compared to the paucity of available steam binding data. Similar to the observed pattern for reactor trip breaker failures, the j operating experience for steam binding events shows that a snali number of plants are apparently experiencing dif ficulties with the check valves f alling to I

prevent backleakage. Thus, the random nature and low frequency of steam binding events should be regarded as potentially important safety problems. But like reactor trip breaker events, the licensee reports fail to connect root causes (when identified) with common mode failure potential. Thus, a major common mode failure may exist that has not been fully recognized by licensees and evidenced by their operating experience. Furthermore, the operational capability of the check valves to perform their isolation function is apparently receiving less licensee attention than did the reactor trip breakers before the Salem ATWS events, e.g., testing and maintenance (See Section 5). However, one important difference between the operating experience for the two events is that a precursor event exists for steam binding events to support the identified potential common mode failure of the AFW system. In summary, steam binding of the AFW pumps represents a potentially significant safety issue. Steam binding of a pump (s) is presently an undetedtable failure that jeopardizes the capability of the AFW system to meet single failure criterion. Further, the operating experience (and AFW designs) shows that the potential for common mode failure of the AFW system due to steam binding of the pumps exists and that the unavailability of the AFW system due to this failure mode contributes significantly to risk of core melt in PWRs. 4.0 'CAUSES FOR VALVE LEAKAGE In order for the hot main feedwater to reach an AFW pump, the water must leak past multiple valves in series. Operational experience showed that multiple check valves in series or in one case even two check valves and a closed motor-operated valve, have leaked in a single AFW train and leakage has occurred in two trains, sometimes simultaneously. Hence, an unexpected number of valves are leaking concurrently. The purpose of this section is to f L

i evaluate the causes for the valve leakages. H. B. Robinson experienced recurring leakage through the check valve (s) and the closed motor-operated valve in both the motor-and turbine-driven AFW l trains at different times. One event involved both motor-driven pumps. The l l identified causes of check valve leakage have included a burr on the hinge, a 1 pin hole in the seal weld, leakage by the seat assembly, and slow closing. The check valves (4-inch Crane, Model 973, drawing NY 434112-5379-306) were replaced with units of the same design, and leakage has continu'ed to occur. The licensee has now decided to replace the check valves with a different design in the near future. The motor-operated valves at Robinson were replaced in 1979 with a different valve design. Backleakage through the check valve apparently caused the'rmal binding of the originally installed motor-operated valve, which the licensee believes caused the valve to leak and fail to open on several occasions. However, leakage has also occurred through the replacement valves. After the turbine-driven pump was steam-bound on July 21, 1983, the licensee reworked two of the three motor-operated valves in the steam powered train. A pin hole was weld repaired on one valve and the seat 1 in the other valves were lapped to ensure a good seal. Until the check valves are replaced. H. B. I:obinson has made changes and additions to the procedures to minimize and detect backloakage in the AFW system. First, the AFW pumps are vented each shif t (the initial time interval was four hours before corrective action on the valves) to prevent a tenperature increase sufficient to cause steam binding of the pumps; and second, the procedure for shutting down the AFW pumps has been changed to delay closing

the motor-operated valves until the check valves have had time to seat properly. t No AFW pump trips or backleakage have been reported since these procedural .f changes were made in July 1983. l The preventive action taken by Robinson suggests that the check valves were not seating properly due to an inadequate pressure differential across the val ve s. For check valves in series, it is not clear how all the check valves can seat properly unless all the valves close at the exact same time, which appears unlikely. As a result, the available number of check valves in series to isolate the AFW system may be misleading because only one check valve may be effectively preventing the backleakage due to the differential pressure available to seat valves in series. This hypothesis is supported by the Surry evaluation of check valve leakages where only three of the twelve leaking check valves showed any damage and the reasons for the other valves leaking could not be determined. The damaged valves were ones located closest to the MFW piping. At Surry Power Station Unit 2, four check valves in each train leaked and each of the two pumps became steam bound.

he motor-operated valves are normally open.

A single check valve near tne discharge of the renaining pump prevented it from also becoming steam aound. All pumps share a common discharge header. Because of previous leakage problems, the check valves were replaced with units the same type (3 a id 6-inch Crane, Model 175.5X, Owg. B-363-534) during the December 1983 refueling outage. An evaluation of d the valves removed fron the AFW systen revelled that the check valves nearest the MFW piping had steam cuts on their seats caused by the flashing of the hot water as it leaked by the valve. The other check valves did not show any visible damage. Hence, the reasons for the failures of these latter check i valves to seat properly are not known. Even after the check valves were l

replaced in December 1983, leakage was again identified in January 1984. The causes are not known at this time, but the licensee continues to evaluate the problem. The plant procedures now require frequent checking of the AFW system for elevated temperatures by hand contact during operator rounds. ) The only check valve failure reported by the Joseph M. Farley Plant was caused by one missing and one worn hinge pin bushing. The check valve failed to close after surveillance testing. However, the three upstream valves were known to be leaking before the test. As a result, gross backleakage caused ) the relief valve at the AFW pump suction to open. The causes for the other check valves to leak have not been determined at this time. One possible reason being evaluated by the licensee and valve manufacturer is the valves ( Anchor-Darling, 4-inch, Model 900) are not suitable for preventing backleakage to the AFW system, e.g., large differential pressures are required to cl'ose the valve. Modifications to the valves are being evaluated as an alternative l to replacing all 24 valves in the AFW systems in both units. Both Surry and Farley plants indicated that they were considering replacing the check valves in the AFW r.ystein (a second time for Surry). Ironically, the i replacement valves under consideration by each plant were the valves that the cther plant was experiencing problems with, i.e., Surry was evaluating the replacement of the Crane valves with Anchor-Darling valves, Wile T3rley was evaluating just the opposite. As a result of our discussions and suggestions, i the plants are now communica;ing and coordinating with each other in an ef fort to evaluate potential replacement valves. A The cause for the backloakagi through the two check valves at D. C. Cook, Unit 2, was identified as incorrect assembly of the check valve internals. i l }

The corrective action was to assemble the check valves properly and to hand-check the temperature of the AFW system during routine shift rounds by the operators. The motor-operated valves at Cook are nomally open. Backleakage through a check valve at Crystal River Unit 3, was identified indirectly because the water heated by the steam increased the pipe temperature which adversely affected the AFW flow indicator. Although it was certain that at least one check valve leaked, the licensee did not check for leakage of other check valves at the time of the events. The plant had experienced numerous failures of this flow instrumentation, but only two of the reported events identified backleakage as the root cause. The latest event (Ref.12) identified steam in the piping which caused the indicator to fail due to high temperature. The causes for the check valve leakage were not identified. The check valve has been reworked and an additional engineering evaluation by* the licensee will be perfomed to detemine if additional corrective actions are necessary. The William B. McGuire event (Ref.10) did not involve leakage of the check valve, but rather, slow closing of the check valve which pennitted MFW to flow into the AFW system, overpressurizing it. To mitigate future events, relief valves were installed in the AFW pump suction piping. However, this action does n'ot address the concern for steam binding. Slow check valve response or failure to close represents another means which could cause failure of the AFW system due to steam binding of the AFW pumps. The reason for the check valves leaking at the KR5k0 plant was not reported. Reference 14 only indicated that the check valves re refurbished.

The plants that have experienced backleakage were not always successful in precisely identifying the root cause for check valve leakage. In general, evaluations are still underway by the affected plants to identify and correct check valve leakage problems. There appears to be no pattern or single major cause for check valve leakage. The causes differ between the events discussed at the six plants where leakage has occurred, and involve different valve designs or manufacturers. In most cases, the check valves have experienced recurring leakage, even after repair and replacement. The causes for check valve leakages will continue to be evaluated. 5.0 LEAX DETECTION Existing regulatory requirements were reviewed to detennine if there are* any requirements for the check valves or remotely-operated valves to be leak tested or whether monitoring the AFW system for valve leakage is part of existing surveillance requirements contained in the technical specifications. These issues were discussed with members of the Containment Systems Branch, j the Mechanical Engineering Branch, the Auxiliary Systems Branch, and the Standardization and Special Projects Branch from the Office of Nuclear Reactor Regulation. The discussions indicated that neither leak testing nor tc5nperature monitoring of the AFW system are required for the reasons discussed below. Regulatory requirements to leak test valves are contained in 10 CFR 50, Appendix J for containment leakage testing and in 10 CFR 50.55a, paragraph g for the Inservice Testing (IST) program. Leak testing is primarily required only for containment isolation valves. For the valves that roccive an automatic containment isolation signal, the technical specifications require that the valves can be closed within a specified time interval.

Although a remotely-operated valve in the AFW system piping is identified as a containment isolation valve pursuant to GDC 57, the valve is not included in the containment leakage testing pursuant to Appendix J because the AFW piping is assumed to be filled with water, precluding air leakage. As a result, the valve is not required to close automatically on a containment isolation signal. The Appendix J 1eakage limits apply to the integrated containment leakage rate and not to specific valve leakage. Thus, even if the valves were included in Appendix J testing, they could be leaking but the total leakage of all valves could be below the allowable leakage rate for the containment, and thus corrective action would not be required for any particular valve or valves. The IST program for valves includes those valves designated as Class 1, 2, or 3 under Section !!! of the ASME Code and whose function is required for safety, and also includes those valves not categorized as ASME Class 1, 2, or 3 but which are considered safety-related. The valve test procedures are pcescribed by Section XI of the ASME Code and the type of testing depends on the category of the valve as defined by Regulatory Guide 1.26. The AFW valves are identified as Category C valves and the IST program requires the safety function of the valves to be verified. For the AFW valves, the identified safety function of the AFW valves is to open to provide a emergency feedwater flow path to the steam generator. Hence, the IST requirements ensure that the valve disc opens freely. The AFW valves are, therefore, not required to be leak tested as part of the IST program. Expanding the definition of the safety function of the AFW valves to include the isolation of the AFW system from the steam conversion system to prevent leakage could result in defining them as Category A valves which would require leak testing of the valves in the IST program. However, the time

, interval between tests (e.g., during refueling outages) would not appear to provide an effective method by itself to prevent steam fomation in the AFW system, especially when small leakages are a concern. This is not to say that inservice testing would not be effective as part of an overall program. For example, the combination of the IST program and periodic surveillance for leakage during the interval between IST tests could minimize the likelihood for steam fomation in the AFW system. The IST program could identify reverse leakage through individual valves and when corrected, minimize the potential for gross leakage to occur simultaneously through all the valves in series. By including these valves in the IST program, the leak testing could additionally ensure that each valve perfoms its intended secondary function of preventing reverse rotation of the pump impeller. The existing technical specification requirenents for the AFW system verify the capability of the pumps and valves in the system to deliver emergency feedwater to the steam generator. The surveillance requirenents do not include monitorin) the AFW fluid for elevated temperature to detect back-leakage from the steam conversion system. The review of the various AFW designs did not identify any instrumentation that could be used for this purpose. At a small number of operating plants surveyed, the AFW piping and pump casings are touched by an operator during his routine rounds of the plant to detemine if the piping is hot. This practice was limited to those plants that had previously experienced backleakage. Typically, the operator checks the piping and pump casings each shift and checks more frequently when elevated tenperatures I are detected. Although this procedure has usually been effective at the af fected plants, 3 pump became steam bound at Robinson altho' ugh the pump was checked every four hours.

. The most effective method of reducing the potential for steam binding of the AFW pumps is to continuously monitor the AFW piping for elevated temperatures between the pump discharge and the interface with the steam conversion system. For example, temperature instrumentation with an alann in the control room could alert the operators that inleakage to the AFW system has occurred such that corrective actions could be taken before the hot water reaches saturation conditions and flashes to steam before or after the AFW pump is started. 6.0 FINDIN'GS AND CONCLUSIONS The evaluation of the operating experience for leakage of hot MFW into the AFW system found that 20 of the 22 events occurred at Westinghouse-designed plants: thirteen events occurred in 1983 at five plants. Some of the events, particularly at Surry, Farley, and Robinson, indicated that backleakage. can be a potential common cause failure for the AFW system. Although the other events affected single AFW trains, AE00 concludes that these events should not only be considered random failures of single AFW trains, but also as contributing events that can lead to potential loss of AFW capability due to a common cause. AE00 believes that the number of identified events is not a true indication of leakage problems at operating plants because leakage into the AFW system is not, by itself, a reportable event. Thus, backleakage may be a more frequent occurrence than indicated by the operating experience. This back-leakage is causing an unwarranted challenge to a safety system. The generic safety significance of this leakage in the AFW system has apparently not been fully recognized. AE00's assessment of the safety significance of the identified events found that (1) loss of a single train due to steam binding is significant because it is presently an undetectable failure that jeopordizes the capability of the AFW

system to meet single failure criterion, and (2) the unavailability of the AFW system due to steam binding contributes significantly to risk of core melt in PWRs. The potential for backleakage may be generic-to other safety systems in both BWRs and PWRs because the standby safety systems are isolated from the operating systems, which are at higher pressures and temperatures, by check valves and a nomally closed motor-operated valve. However, there are no known reports of steam binding of the pumps in other safety systems. Operating experience shows, however, that check valve leakage can cause the motor-operated valve to fail to open due to themal binding (Robinson) or other reasons (Ref.17)--a safety concern different from steam binding. In Reference 17, AE00 recommended measures to ensure the function of the motor-operated valves, which when implemented, should address this concern. In addition, the safety implications of check valve failures to open or leak in other safety systems will be further evaluated. The review of the AFW system designs for the three types of PWRs found that the potential for backleakage is generic to all AFW des gns because check valves isolate the AFW system from the steam conversion system in most operating pl ants. Some designs also employ a nomally closed remotely-operated valve in addition to check valves to isolate the interfacing systems. The AFW designs at Westinghouse plants appeared more susceptible to backleakage than the other designs because the remotely-operated valve is nomally open in most Westinghouse pl ants. Operating experience supports this conclusion although multiple events occurred at Robinson, which employs a nomally closed motor-operated valve to isolate the interfacing systems. The study concludes that the potential for common mode failure of the AFW systems due to steam binding of the pumps is present whenever one pump is

s steam bound because the pumps are connected by common piping (discharge header and/or recirculation piping) with only a single check valve to prevent backleakage - of hot water to a second or third pump. In addition, the capability of these check valves to prevent cross flow between pwnps is uncertain because of a low pressure differential across the valves to ensure they are properly seated. The 22 events represents approximately 60 check valve failures to prevent reverse leakage. The analyses of the causes for check valve leakage did not identify any pattern or single major cause for check valve leakage. The causes differed between plants and involved different valve designs and manufacturers. This study did not identify any regulatory requirements or uniform plant practice to reduce the likelihood of steam binding of the AFW pumps. Presently, there are no regulatory requirements to leak test any of the valves isolating the AFW system from the MFW system as part of the contaimnent lepk rate testing-or inservice testing programs to ensure the isolation function of the valves. Existing technical specifications presently do not contain surveillance requirements to monitor or detect leakage into the AFW systen. A small number of plants presently have aj[ hoc procedures for the operator to touch the AFW piping to detect elevated temperatures during routine shift rounds. This practice exists primarily at those plants that have experienced backleakage. The loss of the AFW system due to steam binding of the pumps is a potentially significant safety issue requiring attention. The loss of the AFW system is a major contributor to dominant core melt accident sequences. Although an l Infor. nation Notice was issued to alert licensees to the potential for backleakage and steam binding of the pumps, adequate measures to detect and monitor l backleakage do not now exist in all plants to minimize the likelihood of the common mode failure of the AFW system. l

. 7.0 RECOMMENDATION AE00 recommends that the Office of Nuclear Reactor Regulation either (1) require the regular monitoring of the AFW system to detect leakage and ensure that the fluid conditions are well below saturation conditions; (2) confirm that such a practice is already being implemented; or (3) determine that backleakage is not a safety problem and no additional actions are necessary. The purpose of this recommendation is to minimize the potential for steam binding of the AFW pumps due to backleakage to the AFW system from the steam conversion system. The method should include two basic elements: first, preventive measures to ensure that the valves can perform their intended function; and second, surveillances to ensure that the valves' isolating function has not degraded with time. For example, the first elenent could include leak testing of the* isolation valves in the AFW system as part of the operability requirements for the system. This testing could ensure that the valves can perform their intended function and be maintained in an operational condition required for safety equipment. In addition, this testing coIld identify individual leaking valves and minimize the potential for gross reverse leakage through all valves. Leak testing could be required prior ta a startup from an outage if testing had not been completed in the previous six months. However, this element by itself is not considered to be fully acceptable, because of the long time intervul between leakage tests. The second element suggests a technical specification surveillance require-ment to monitor and detect backleakage during the leak test interval as part of the operability requirements for the AFW system. For example, a

~ temperature limit on the AFW fluid could be required as a Limiting Condition for Operation. In order to meet the Limiting Concitions for Operation, the tenperature of the fluid must be known. The fluid temperature could be obtained either by (1) installing instrumentation to c'ontinuously monitor the tenperature near the discharge of the AFW pump with an alarm in the control room, or (2) measuring the tenperature periodically using a hand-held pyrometer. The plant procedures should adequately address corrective actions to be taken in response to a high tenperature condition. The frequency in the latter case might be adjusted based on the history of measurement results, i.e., increase the frequency if the tenperature is frequently found high, or decrease the frequency if the temperature is routinely found acceptable. In the interim, until an approved method is implemented at operating PWRs, plant administrative procedures should require an operator to measure the tenperature of the AFW piping and pump casings with a pyrometer and record the reading in the check-off lists that are used during plant tours. These actions should ensure that backleakage is minimized and detected before a pump becomes steam bound, and reduce the likelihood for the canmon mode failure of the AFW system. l i r l

8.0 REFERENCES

1. Menorandum from J. Heltemes, Jr., to R. DeYoung and H. Denton, NRC, ~

Subject:

Vapor Binding of Auxiliary Feedwater Pumps, dated November 21, 1983.* 2. Carolina Power and Light Company, Licensee Event Report 83-4, Docket 50-261, dated May 18, 1983.* 3. Carolina Power and Light Company, Licensee Event Report 81-016, Docket No. 50-261, dated July 10, 1981.* 4. Carolina Power and Light Company, Licensee Event Report 83-016, Docket No. 50-261, dated August 19, 1983.* 5. Carolina Power and Light Company, Licensee Event Report 79-34, Rev.1, Docket No. 50-261, dated March 25, 1982.* 6. Indiana and Michigan Electric Company, Licensee Event Report 81-063, Docket No. 50-316, dated November 30, 1981.* 7. Indiana and Michigan Electric Company, Licensee Event Report 81-032, Docket No. 50-316, dated August 11, 1981.* 8. Personal communication with Eric Swanson, Senior Resident Inspector,* D. C. Cook Nuclear Power Plant. Event similar to References 4 and 5 occurred on January 16, 1983 but the plant was in an operational mode which did not require a report from the licensee. 9. Duke Power Company, Licensee Event Report 81-136, Docket No. 50-369, dated September 8,1981.* 10. Florida Power Corporation, Licensee Event Report 83-43, Docket Number 50-302, dated November 2,1983.* 11. Florida Power Corporation, Licensee Event Report 82-076, Docket Number 50-302, dated January 19, 1983.* 12. Virginia Electric & Power Company, Licensee Event Report 83-55, Docket Number 50-281, dated December 16, 1983.* 13. Letter from T. R. Tramm, Commonwealth Edi son Company, to H. Denton, NRC,

Subject:

Byron Station Units 1 and 2, Water Hammer Protection for Dockets 50-454, 50-455, 50-456, and 50-547, dated September 9, 1982.* 14. Carolina Power and Light Company, Licensee Event Report 77-18, Docket No. 50-261, dated September 6,1977.* Available in NRC PDR for inspection and copying for a fee.

+ ' 15. Memorandum from D. Zukor to C. Michelson, NRC,

Subject:

Engineering Evaluation Report on McGuire Overpressurization Event of August 25, 1981, AE00/E248, dated November 2,1982.* 16. Alabama Power Company, Licensee Event Report 83-84, Docket Number 50-348, dated December 27, 1983.* 17. Memorandum from C. Michelson to Multiple Addressees, NRC,

Subject:

Survey of Yalve Operator-Related Events Occurring During 1978, 1979, and 1980, AE0D/C203, dated May 28, 1982.* 18. U.S. Nuclear Regulatory Commission, " Reactor Safety Study Methodology Applications Program: Sequoyah #1 PWR Power Plant," NUREG/CR-1659, Vol.1, dated April 1981.* Available in NRC PDR for inspection and copying for a fee.

8 O A-1 APPENDIX A i YAPOR BINDING OF AUXILIARY FEEDWATER PUMPS 4 = 4 L

A 4 ge> ct% f* 4,, UNITED STATES .y ,p NUCL E AR REGULATORY COMMISSION ~ t4 c us.uwcTow, o c. rosss j mm q "%..".. / NOV 211983 HEM 3RANDUM FOR: Richard C. DeYoung, Director Office of Inspection and Enforcement-Harold R. Denton, Director _ Office of Nuclear Reactor Regulation FROM: C. J. Heltenes, Jr., Di rector Office for Analysis and Evaluation of Operational Data

SUBJECT:

VAPOR SINDING 0.F AUXILIARY FEEDWATER PUMPS Enclosed is an engineering evaluation report on the vapor binding of the auxiliary feedwater ( AFW) pumps at H. B. Robinson Nuclear Power Plant, Unit 2. The safety implication of the events at Robinson is that the leakage of main feedwater to the AFW system constitutes a common cause f ailure that can render both trains of the AFW system inoperable, a]- though only single trains have been adversely affected to date. Similar events have also occurred at D. C. Cook, Unit 2. The potential for the loss of AFW systen due to backleakage appears generic because the designs of the systems at Robinson and Cook are typical of other PWRs, i.e., isolation between the steam conversion system and the AFV system is accomplished by check valves and motor-operated valves. AEOD has initiated a case study to better define the generic implications and establish the bases for revising the-technical specifications to ensure that the AFW tenperature is monitored and/or that the inservice inspection programs test the isolation capability of the check valves. In the interim until the case study is completed, the Office of Inspection and Enforcenent is requested to issue an Information Notice to promptly notify PVR licensees of these events and alert them to the potential for leakage from the feedwater system to the AFW system and steam binding of the AFW pumps. The Office of Nuclear Reactor Regulation is provided a copy of the report at this time to highlight the significance of the events and provide an input into ongoing NRR activities. We have only recently become aware of TIA 82-66 entitled, " Robinson / Crystal River 3 - A W Check Yalve Leakage," and endorse the action *w evaluate generic technical specification changes. It is important to note that Robinson events analyzed in the enclosed report have occurred since the TIA was initiated in 1982. These events may pro-vide additional information pertinent to the resolution of the TI A. LJ - j q'X }j 'i ~ s. ,\\ h

A-3

.. If you require any additional infont.ation, please contact Wayne Lanning at ~ 492-4433. He is avai.lable to assist you in resolving this important issue. IgW C

Heltemes, r., Director e for Analysis and Evaluation

~ of Operational Data

Enclosure:

As stated cc w/ enclosure: J01shinski, Region II GHolahan, NRR JPage, NRR RBaer, IE 9 = l

A-4 AEOD ENGINEERING EVALUATION REPORT

UNIT:

H. B. Robinson, Unit No. 2 EE REPORT No.:AEOD/E325 DOCKET: 50-261 DATE: November 21, 1983 ~ LICENSEE: Carolina Power & Light Company E/ALUATOR/ CONTACT: W. Lanning NSSS/AE: Westinghouse /Ebasco

SUBJECT:

VAPOR BINDING OF AUXILIARY FEEDWATER PUM3S AT ROBINSON, UNIT 2 EVENT DATE: April 19, 19$3

REFERENCE:

Carolina Power & Light Company, Licensee Event Report 83-044, Docket 50-261, dated May 18, 1983.

SUMMARY

Robinson has experienced 4 failures of AFW pumps due to low discharge pressure trips caused by steam fomation in the AFW piping and pump casings. The steam was fomed when hot water from the feedwater system leaked through two check valves and a motor-operated valve in the piping to either the motor-or steam-driven AFW pumps. Although the backleakage has' caused only a single train of the AFW system to fail, the potential exists for both trains to fail simultaneously since backleakage has occurred repetitively in both trains. Three events have also occurred at Cook-2 involving backleakage and elevated temperature of the AFW piping and pump casing. The evaluation concludes that Robinson has implemented acceptab'le corrective actions to prevent steam fomation in the AFW system. Since the design of the Robinson AFW system is typical of other operating PWRs, an IE Infomation Notice should be issued to infom other licensees of the potential for steam binding of the AFW system. An AE0D case study is recomended to further evaluate the generi,c implications for other AFW systems and develop appropriate recomendations to minimize the potential for steam binding of the system. Generic technical specification changes should be evaluated to require that appropriate surveillance procedures be implemented, if not already available, to detect leakage and prevent steam fomation in the AFW system.

This document supports ongoing AEOD and NRC activities and does not represent the position or requirements of the responsible NRC program office.

nho fhb %,,7 't I h'\\) k

a-o ' + DISCUSSION During the review of operating experience, the referenced LER was identified as a significant event and warranted AE00 evaluation because of the potential for common mode failure of the auxiliary feedwater ( AFW) system. The purpose of this engineering evaluation is to summarize the event, evaluate the safety implications, and determine whether additional licensee or NRC actions are nec es sary. Following a manual reactor trip on April 19, 1983, the two motor-driven auxiliary feedwater pumps started automatically on low steam generator level. Af ter about 2 minutes, the "B" AFW pump tripped. During testing of the pump, a significant amount of steam was vented from the pump casing. The pump trip was attributed to a protection trip signal generated by the pressure instrumentation in response to a low discharge pressure. The discharge piping from the motor-driven AFW train is connected to the main feedwater piping neag the steam generator. Hot wa ter ( about 425*F) from the feedwater system leaked through two check valverand a motor-operated valve in the piping to the AFW pumps. This water flashed in the discharge piping and pump casing because the AFW system was at a lower pressure than the feedwat?r system. When the AFW pumps started, the instrumentation in the discharge piping sensed a low pressure and signalled a pump trip. The low discharge pressure was caused by steam binding of the pump wnich reduced the flow and prevented the discharge pressure from increasing above the low pressure setpoint in the 30 seconds required for the discharge pressure sensor to time out. Condensation effects would contribute to the low pressure condi tion. The potential exists for both motor-driven AFW pumps to trip due to backleak-age in any one of the discharge piping runs to the steam generators because both pumps share a canmon di scharge header. This is evidenced by the elevated temperature measurements obtained for botn pump casings during the licensee's investigation of the event. The steam-driven pump has separate di scharge piping and was not affected directly. However, the motor-driven and steam-driven pumps share a common suction header from the condensate storage tank and backleakage could affect all pumps. Although the pumps have a conmon suction header, the relatively cold concensate storage tank water would tend to mix with the hotter water from the steam generators reducing the potential for water at the suction of the AFW pur?S to be near saturation conditions and flash wnen pumped. Thi s w3ul d depend, of course, on the leakege r.ite and the time available to raise the temperature of the suction water. Based on this event, the combination of these two f actors did not adversely a ffect either the second motor-driven AFW pump since it did not cavitate o the steam-driven pump since the su: tion water renained cooled. Robinson had experienced prior leakage through the discharge piping and consequent trips of the motor-driven AFW pump "A" on June 11 and 16,1981 (LER 81-016). The unit was at 93% power during the second event with only a single AFW pump remaining t3 provide emergency feedwater because the steam-driven pump was inoperable. The valves were repaired and the backleakage significantly reduced. The pump tripped again on June 19, 1981 (LER 81-17) af ter a! reactor trip, but tne cause was attributed to improper throttle

a 4' valve setting of the discharge valve although steam binding could have caused the low pressure trip. On July 21, 1983, a similar event (LER 83-016) occurred resulting in the steam-driven AFW pump being declared inoperable due to potential steam binding. Hot water from the feedwater system leaked through tne discharge check valve and the motor-operated valve producing steam at the suction vent an6' discharge drain of the pump. The discharge piping from the steam-driven pump is connected to the feedwater bypass piping. The potential existed for pump cavitation and trip on low discharge pressure following an automatic start. The steam was discovered during a routine check of the AFW train and the pump'had not been required to operate. On August 17, 1977, the steam-driven train experienced a failure of a check valve to close which caused the relief valves on the suction header to lift. Other failures of the motor-operated valves occurred on Septenber 5, 6 and 18, 1979 when they f ailed to open (LERs 79-32, 79-33 and 79-34). The cause for the failures was due to a thermal overcurrent relay trip resulting from the failure of the torque switch to de-energize the motor af ter the valve was fully closed. Excessive wear of the worm gear prevented proper operation of the torque switch. The excessive wear is believed to have occurred during previous events when the valve stuck closed due to thermal binding caused by the leaking upstream check valve. Thermal binding can lead to deformation of the valve internals and leakage. The three check valves and the three motor-operated valves were replaced with the same type (4-inch Crane,model 973, drawing NY434112-5379-306) in 1980 to correct the backleakage. The design of the AFW system at other operating plants also generally include check valves and motor-operated valves in series to prevent backleakage from the feedwater system to the AFW system. This suggests a potential generic concern. However, a review of operating experience for the past 2 years identified only three similar events. These events occurred at Cook-2 (LERs 81-32, and 81-63) where the valves leaked in the steam-driven train and an abnormally high temperature was observed for the pump casing, suction and discharge piping. The pump had not been required to operate in any event. The Resident inspector identified the third event wnich occurred on January 6,1983. This event was not reported in an LER because the mode of operation did not require the AFW system to be operable. Although the design of the AFW system at Cook is similar to Robinson, the motor-operated valve in the pump discharge piping is locked-open during l operation. The isolation of the AFW system from the main feedwater system is achieved by two check valves (4-inch Atwood Morrill, arawing #20216F). The reason for the check valve leakage is attributed to improper valve assembly rather than design deficiencies reported f or the Robinson valves. N ev e rthe-less, the potential for bacileakoge may be greater at Cook than Robinson, because the motor-operated salve does not provide isolation capability. However, the consequences of backleakage at Cook is significantly less, because the motor-driven punps do not share a common discharge header, e.g., both pumps cannot become steam bound due to leakage in a single l discharge line. All the pumps do share a common suction from the con-l densate storage tank. Like Robinson, there are no temperature indicators for the auxiliary feedwater. The events at Robinson and Cook suggest. that backleakage is a potential generic concern since different check valve l u

=. w. n

4*

designs are employed in the AFW system and both units have experienced backleakage resulting in inoperable trains of the AFW system. A special interim procedure has been implemented at Robinson to vent both ~ the motor-and steam-driven pumps once each shift. In addition, the temperature of the pump casings are monitored locally and the pumps are operated as necessary to ensure that the water-1n the AFW system remains cool and well below saturation conditions. Cook also monitors the temperature during routine checks by the auxiliary operator during shift inspections. In the longer term, Robinson is evaluating a design change or replacement of the check valves located in each of the AFW pump discharge piping. Depending on the results of the evaluation, the check valve leakage should be corrected during the refueling outage beginning in December 1983 or ducing the steam generator replacement outage beginning in June 1984. A program is also under-way to improve the performance of limitorque valves by developing valve per-formance histories to monitor and identify valve degradation in the future. FINDINGS AND CONCLUSIONS Robinson has experienced four events in the past two years involving 4 failures of AFW pumps due to steam binding resulting from leakage of feed-water to the AFW system. It appears that the failure of the check valve to prevent backflow causes the motor-operated valve to leak and is tne primary cause for the events. Based on operating experience the leakage in one AFW train has not affected the other train although the potential exists for common mode failure. The primary concern is, however, that backleakage will occur simultaneously in each of the AFW trains causing failure of the AFW system to perform its safety function. The safety implications of the four events at Robinson is that the leakage of feedwater to the AFW system constitutes a common cause failure that can render both trains of the AFW system inoperable. Although the events to date have involved the failure of a single train, all of the events have been caused by the simultaneous leaking of two or three isolation valves in se ri es. These events should not be considered random failures of single AFW trains, but as contributing events leading to potential loss of AFW capability due to a comron cause failure. The trend of these events compare similarly to the trend of the reactor trip breaker failures at Salem and other plants before the Salem ATWS events. Since the design of the AFW system at Robinson is typical of other PWRs, the potential for backleakage exists in other operating plants evidenced by the events at Cook-2. Monitoring of the temperature of the AFa' pump casing, suction and discharge piping should be performed on a routine schedule to detect leakage into the AFW system and prevent steam binding of the system. Robinson has implemented procedures to ensure that the water in the AFW system remains cool to prevent steam formation. These preventive actions should en-sure that the AFW pumps are available to perform their safety function until the check valves are redesigned or replaced to correct the lea < age problem. Efforts to improve the performance of the motor-operated valves are also under-The licensee's actions appear acceptable and no additional actions are way. believed necessary at this time.

-4 ~ 0 RECOMMENDATIONS The Office of Inspection and Enforcement should consider issuing an information notice to inform other licensees-of the potential for loss of AFW capability due to backleakage and steam formation in the AFW system. In the near future, AE00 should complete a case stucy to evaluate the generic implications for all PWRs and identify and establish the bases for changes to In addition, the requirements to include the AFW technical specifications. pump discharge motor-operated and check valves in the inservice testing pro-grams should be evaluated. G O 9 -}}

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