ML20140E667
| ML20140E667 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 08/22/1995 |
| From: | FLORIDA POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20140E502 | List: |
| References | |
| FOIA-96-485 JPN-PSL-SENP-95, JPN-PSL-SENP-95-101, NUDOCS 9704290087 | |
| Download: ML20140E667 (396) | |
Text
{{#Wiki_filter:_ _ . . . . . _ _ . _ . _ _ _ . . . __. ._ _ _ _ . _ _ . _ _ _ _ . . _ . _ _ _ _ _ _ _ . _ . . _ _ _ _. __ _ _ _ _ _ . 1 1 ! l
- 1 i
i ! l 1 4 FLCRZnk POEWL E LIGET CO j i ! l 1 1 1 - Ess33EERZXG LTALMTZON i l Assessment of the Effects on Plant Operation ! ! of TWng the LPSI Pump DL-harge Header Thermal
- Relief Valve !
i I l sT LUCIE NUCLEAR PLEMT 4 -l UNIT 1 i i 1 i i ers-esr.. anus-es-ses 357E3205 1 SEFETE REE4WED t. 9
..a
. ,g;p ,
9704290087 970423 , PDR FOIA BINDER 96-485 PDR
j' 11-N-1995 10:32AM St Lucle Res1 dent Office 407 461 4622 P.02 AUG E2 '?S C3:31PM PCL PE2 7Jo BEACH
^M j .7:t-F3:-sI:::P-s .
- REVISION i j . PAGE 2 0F B J
- REVIEW AND APPROVAL RECORD r
1 i
- PLANT IT. Luc!E UNIT 3 1
) TITLE Assem+= ant of the Effects on Plant onoration cf liftina the LPSI P= Dineharee Desser Thennal Relief Valve i 4 LEAD DISCIPLINE LICENSING a
- i i i k* !
1 !' ENGINEERING ORGANIZATION DRODUCTION ENGINEERING-GROUP . i l i l REVIEld/ APPROVAL: i j
- INYtRFACE TYpt )
l GEDUP PREPARED VS1FIED APPRCVED FPt,ApptDWEa'
- INPUT RttttV g n/A i mmmmmmmml
! #tCM X l tttc7 X ! lac I . l CfYIL i X __ . j } (IC" LEAD IMbl'M7" , bb.* n' j- up I _ n \A i I nec sugn. x $WULkHT J " h fsf fW hd* / ___ , !. psa kk \ Y / l V p- !
- For Centeseter Evals As Determined 9y Predests " netter laterfose As A Ntn om,A11 10CPRIS.88 tsale eng PLas I
FPL PROJECT 3 APPROVAL: BATE: kSk 4 ' W-i OTHER INTERFACES Mone , i ao i JPN Fors 34, asy, s/t; 1 l J i
l'-08-1995 10:33AM St Lucie Restosnt Office ; 407 461 4622 P.03
# #9 oys C2 '% 23:31PM PSL EG M C N
."T:* -? EI.- E L' T '-
REVISION PAGE 3 0F 3 TABLE OF CONTENTS j I 1 SECTION ZZZLE R&g1 l Cover - 1 1
- Review and Approval Record 2 ;
- Table of Contents 3 1.0 Purpose add Description 4 ,
I 2.O Backgrounc 4 l 3.0 Design Bases 4 4.0 Analyses cf the Event 5 5.0 conclusions 7 !
, 6.0 Verification Summary - 7 7.0 References 8 Attac:hments Nona .
S e e
1*.-08-1995 12:E;#1 St Lucie Residem CHice
- 437 461 4622 P.04 ca.C 22 #95 23121PM PSL TEG Aho ECACH
'M l
.;pw-uBT.-GENP M REVIS1GN
!j PAGE 4 0F B ! 1.0 EH17982_AMD ScoFE On August 10, 1995, low pressure safety injection pump (LPSI) l
- discharge header thermal relief valve V3439 lifted releasing about j 4000 gallons of reactor coolant into the reactor auxiliary building (RAB).
i' The purpose of this ovaluation is to assess the significanoe of ! this event on plant operation. More specifically, this evaluation , l assesses the affsets of this event during normal, shutdown and i'
- design basis accident conditions.
I i This angineering evaluation involves angineared safeguards systems 4 and la therafore classified as safety related. i 5.0 . ., n - ra. l On August 10, 1995, reactor coolant water was discovered flonng i from the pipe tunnsi door at the -0.5 elevation of the RAB (Ref :.) . Subsequent investigation revealad that the LPSI pump discharge j header thermal ' relief valve (V3439) van lifting and would not i ressat. Based on the dimensions of the pipe tunnel and depth of { water, and the amount of water that filled the aerated wasta i' storage tank, it was estimated that approximataly 4000 gallons of water had discharged from the relist valve. In addition, the safeguards pump room sump isolation valves (which includes the pipe tunnel drain valves) wara found to be closed and the two Western pipe tunnel floor drain lines were clogged. The relief valve flow rate is 40 gym at the relief setpoint. 3.0 nemian Basis neview W T Discharce Mandar Tharrr.a1 Relief Valve: fFEAR Section h3.2.2.6.c) The LPSI discharge header thermal relief Valve provitas overpressure protection due to fluid thermal ion for am isolatable section of the LP5I system discharge pi ing. R&B Waste Manaamment Evaten The RAB wasta - - - t system includes the pipe tunnel floor and drainage system which is the discharge point for the themaal relist valve. Tbis discharge is directed via the RAB drain system to W safeguarde room sumps. Water in this 'aump is normally pumpec automatically into the equipment drain tank (EDT) upon high level where it is then pumped into the aerated wasta storage (AusT). 4
_ - . - . . _ - . - - - - - - - - - - - ~~~^' ~"'~'^^ ~ ~ ~ ~ ~ ~ 5 11-08-1995 10:33AM St Lucie Res: dint Office 1 407 461 4622 P.05
.s/9 l
Ar. ZZ '*5 23:32PM PSL PCG JUNO E M i 27N-95L-SENP-M - REVISION . ' PAGE 5 OF 8 L From the control room, an alternate path can be aligned to pump tha ' f safeguards sump . water to the reactor drain tank (RDT) u the containannt building (PsAR section 11.2.2.1) . This alternata path { is the leakage collection and return system (LCRS). It is a d dedicated system which is nozzally aligned to the reactor drain j tank (RDT) following a racirculation actuation signal (Ref 2). h "A* and asa safeguerds room sumps each have 2 sump pumps, etach i
- with a design operating flow rate of 50 gpa at 100 ft. of head.
l The sump pumps are powered via non-vital MCcs n2/132. The ' safeguards high and hign-high sump alarus are powered from vital Mcc 1AB. I The function of the safeguards pump room sump isolation valves
. (HCV-25-1 through 7) is to isolate the safeguards rooms from RAB flooding due to a fire main break (FSAR section 3 5A-110) . The i
sateguards pump room sump isolation valves are normally open ro < allow drainage to the ECCS sump. j i 4.0 m1vais of Effnets of Liftimr vsast { l The lifting of v3439 will occur while on SDC if LPSI pump operation i results in LPsI discharge header pressuras raaching the relief j valve setpoint (500 psig : Jt) . Sufficient pressura to lift the
- relief valva any occur curing LPs1 pump starts that result in a pressure spika (eso psi). The pressure spike in conjuction with the pumps AP of 182 pai and a suction pressure of between 257 and 3sa pies, will reach the minimum design setpoint. With the blowdown for the valve set at 144, the valve will continue to relieve until system pressura drops below approximately 430 psig.
Therefore, the analysis in this evaluation will only consider l operation that involves LPSI discharge pressures approaching tia j relief valve setpoint. (LPsz discharge pressures will not exoand i relief valve setpoint during operation with the shutdown cooling j system isolated from the RCs.) l Emma of RCS Tnventerv l If v3439 lifts duEing normal shutdown cooling (SDc) operation, loss 1 of reactor coolant will occur.until SDc is secured or the relief Since the flow rate through -ha valve at the - valva rassats. setpoint pressure is limited to about 40 gym, tha rate of inventory less is well witnin normal charging system capability. During long tars cooling following a design basis mooident the s6c systen may be used to satisfy the acs heat renoval safety function. Assuming the soc system is being utilised, then tha inventory loss of 40 gps is well within askeup onpability of either the high pressute safety injections pumps or anerging pumps. 4 9 e Fl
l 11-08-1995 10834AM St Luc 1e Resadint Offiee 1 407 461 4622 P.% AUG 22 '95 23832PM PSL PEG ANO BCACH '4 ! , F W F 3 1. .3 ::;r7 - 9 4 - l } REVISION . PAGE 6 0F 8 l Lamm of RWT TMven h I During the injection phase of small break loss of coolant accidents ! (LOCAs), excess steam demand events (EsDEs) and steam generator tube rupture (SGTRs) with LPSI pumps aligned to the refueling vatar i tank (rut), LPsz pump = n4=um;disanarge pressure is about 230 peig l (ENT head plus LPsI pump Ap). This is wall below the lift er,tFoint ' , of v3433. Tharatore a significant loss of RWT inventory would not
- occur.
4 Iass or containannt Sumn Inventerv During the recirculation phase of tacAs, the LPSI discharge header l pressure will not approach the lift setpoint of v34ss. This is , j l because tha LPSI pumps are either automatically stopped on race.1,pt of a recirculation actuation signal, or if used for het 14g j j injection, maximum LPsI discharga header pressure would be = 250 i pisa (containment sump head plus LPsI pump ap) , wall below tha lift j setpoint of v2439. Therefore a loss of containment sump inventory )
- would not occur,:.V l '
i Floodine in the Pine Tunnel During the subject event the pipe tunnel floor drains vare isolated j vhich caused flooding in the pipe tunnel up to the height of the j lip on the door (=10") . Ramator coolant then spilled into the ans ! t hallway where it was than routed to the "B" safeguards room sump via an ras floor drain. The lower levels of the pipe tunnel do not contain electrical equipment that is susceptible to faults from a i flooding event of th:,s type. l ) l When the safeguards pump roca sump isolation valves are open, tha discharge of v3439 is directed to the floor drains in the R&B pipe tunnel at the .5 ft. elevation. These drains empty into the
, safeguards room sumps via normally opened air operated valvas i controlled from a single switch on Ersa los. The capacity of these drains exceeds the 40 gpa relief discharge, and theratore, the pipa tunnel will not flood if the drains are available.
) Floodimr in na'#Be enemmsavde p.mn_gan. 5 . l Ihe "B" safeguards room sump holds 1100 gallons and automatically j pumps down to the equipment drain tank (EDT) at m 350 gallene at a rate of 50 gpa (oapacity of one sump pump) . If level ramahaa.950 gallone, the samand pump starts. Assuming non-vital' power t.o tan pumps is mainta , f3. coding of the "B" safeguaats room will not ooour. Assuming a loss of offsite power (i.e. , ne safeguarde sump pumps avai3able), and that the discherged water is undatestad (i.e , no operator intervention), the water laval in the sar room. weald reach the "B' Ep5E pump notar la er 7 s. Annunointion of the safeguards high and high-high sump alarms votid require investigation te determina the reason for the alarm (pet 2). Seven hours is ocasidered suffiaf% time to identify and isolata the leak prior to 1mse of tha 838 EP53 pump. h
- e w Q '*..,5 l.
- l'.-08-199E 10
- "FAM St Le e Res:oent CHiee 1 307 461 4622 P.07 i tug 22 'M 23:33PM *EL FEG !LNO EEACH M
l
~
- ~2! "E*',-EIS -o' i j
REVISICS . PAGE 7 CF S
- f i
i Tnernames in RadIolocrieml Conummiences of Danicrn namin lecidents d i I
- .small break LOCAs, ESDEs and SGTRs are the design basis accidents that could involva lifting of V3439 sa.nce these events could result i in the SDC system being placed in service with navunum suction l pressure (i.e.,$6spisa) supplying the LPSI pump (s).
FSAR analysis of. small break LOCAs, ISDEs and SGTRs demonstrate that these events involve fuel damage only because extremely conservative assgnptions are used to stepresent the limiting design parameters for tga plant ana the fuel. For example, ESDEs assume 2 the most reactive rod stuck out of the core in order toiachievs a i return to power. (St. Lucia Plant has never, experienced such an
- event.) Using conservative assumptions of this typa ensures thst
. the F5AR analyses envelop the range of possible plant condititiis ' that may exist during the life of the plant. ! A review of TSAS analysis of small break LOCAs, ESDEs and s'X.a j demonstrates that these accidents will not result in fuel damage if
- assumptions tha$ reflect the actual operating history of the plant j are applied. Tharatore, the radiological consequences of these
- YsAR accidents will not be increased and the FSAR offsite desas 4 remain bounding.
h . . ! 5.0 cjg5@USIDES ( i i The safety significance of lifting V3439 with respect to plant - operation has banen evaluated. The offacts of loss of inventory, j RAB flooding and) radiological consequences were reviewed and it is i concludeti that the lifting of v309 would not have a significant l
- affect'on safe plant operation during normal, shutdown and design l i basis accident conditions. i 4
t
- 6.0 VERIFICATION schMaEY
(- i The scope of this verification was to review the inputs to i determine if the".results were reasonable. The method used for this ! verification consisted of ensuring that the applicable references, ! oodes, and regulatory requirements were identified and addressed. j The inputs are correctly 7 selected and applied. l The conclusions, hided are reasonable with respect to the inputs and discussions. The verifier aaa s with the Noelmer safety j Ralated classification of this Engineering Evaluation. The rationale in as, signing the safety casselfication was. verifand , i against the requLrements of .7Mr Quality Instructions. The verifier concurs vith thi conclusions out14and above, I
\
. _ _ . . _ - . _ . . . _ ._ _ _ _ _ _ _ . _ . . _ - _ _ _ _ _ _ . . _ _ _ . _ . ~ . . . . _ _
1;-06-;995 10:25M St i uc te TostoInt 0Hice 407 .261 4622 i P.08 QUG 22 '?5 23:33Ffi FSL PEG Arc EFJCH ' e2H-25L-sDG-v5 zur R2 VISION 1 i PAGE 8 OF 3 4 D.
7.0 REFERENCES
1
- 1) In-Housa Event IRE-95-046, dated 8/17/95.
1
- 2) . St Lucie Unit 1 Energencf Operating Procedure 1-gop-03, Loss
' of Coolant iccident, Rev 12.
- 3) 5t Lucia Unit 1 Plant Annunciator Summary Procedure ONP 1-
'0030131 Rey 60 (Window R-14)
- 4) 5t Lucie Unit 1 FSAR, amend. 14.
l' l t 6 5 . l.
?!;
o . 1
~
s e e O
+
TOTR. P.00
11-08-199s 12:24en ss tuci, g,d*"' " ' ' 407 461 4622 P.e2 ! l , l 1 ST.LUCIE ACTION REPORT _.. . mime j
'*A one_;L[ti o _97 siane GL%ts't f,
i "_=_'_',A 'MA.L. *_suo,. -r S - ,,,,,,.in -4 he ,,, g ,,_ \
- n W l m g ou 4.au ne a o t .s x.u:ma um,m uv. eu-n; n, 9sto u L a e~aa v. --,w ~ u.. a ~ am e. .as, , ( ,
, ,, o u
.sa mers. rw s . ma ,a s i. u. m .c m ^
k'*-a, h._ i va s km 4 em1.a t
- A 1 aJ [k. . b4*t t .L A a. AL A- s indMdualNamed i
i L. .t'
\
t .. ....~t.,, ,a mg __ l
' t.sessen i
. o e ,.orme e v. O . l
$<1 - _ or - e . .. - e.e.r . l l ma mmsen - w nu ek -
%n a n o t -s . es s I lf
! j Dl .
\
l ansons - I4 j 1. won any ampstahanenesgenst vos C No - C. OE t whatwensewyandwarsesysumanade n tuaufr ou nau3 gh % -,. -- - - . ! a ntum m u_--.J, j .a ut . a.a ~ '--.. a L.- <- l 3-.-- 1
- s. auspeceedemussef onnesen. A -- ai- su ,-- o - l j
? - - - i- 4.- - * - - - - - - '---.m.- , - - . ~ . A neemmmenessen m oonest ens osporensra l -: a m .m . - % s ..
. , 4,...,d au n. __ _ .. , m . " . _ , , , , , . _ f osserenantHess C. N d 3 / 1/nMt' ospu e M eesseet 'Ives O m
, m eanne osse RE%g:ev/ APPROVAL i I }
- 1. AssignseDepenmenWinedeuel 'T2M' iT### /b J0'## _
! 2. Rouete les C Yes h sTA Yes N ' 1'
- 3. PP400 C 9988 0 4 Evenuedenausby M / fffonocevemeasuressongsenedIpy_ C s i_
/M'D/3I#Moonusoeuireenvoweiaekest w
% C No YWs C No
- 1. Nomammans. 4P6m ansAP m .OlH0731,9540
,wneuies a ns,. ftsedred an*enri. Non n Rou.gne Nomen.onsO& mvmemmie SP 900815 *Repareg W salaguuses Even.')
- 3. EvertType14_ j C pop Ugnease Den
- s. assurerenne Yes No O ME
- 1. leoperabaresemesmerenomdseseromruiriusdspadent C Yo* Oas
& Does mis hem put us in en aden sessnantt O ves O Ne vesvosa. i ourusen A. DoesthistemdedmeasyssumerosmponertOost O v== 0 as whiscodem r=
A What immodnes asesudens nem snads? 0540. EPA, ang
/ * '"
s.isnemameeshow? O vas @ Paar* 6 6 *D
- e. Ames.nm v.s.n. han. ~
/
as.== us ,
,, =_ N do.fs.as.ItRW . 4 -w .c .
.;; 7,._ _ ...
. f, .!I.. .i$
' ~b l
4se,arsers; e yr ,w.i [, k .n win C. d. ukA g ,,..pp,-
- N '
cx se-, ! k. L +JA alws e. ,e e. U b (ed A k<r b . e(nre / g h au N. nin. r U-sw ; 4 m se u ear *# wmse . Tlte ts r., lJ r )i luvt%44 , har u n43 N s4 - , c_ A Le h'f.4td. Te en. -~ (L A M I, krA 0"** 88 ! e. d .n. +4 :4. d .rrJ:U. , w. l k J6 LA , .s nMsV . In8&olNamed l TLle) L, e4.ud. Alan,l MuL r=48!*c .sh.Jd'd.=-. tku.ld s.Looedon l I O # e
}
^
% NO i
b ( _ l 'd d'*""
- 1. Were cry steps talen to mid0.ast O Yes No a
! .w or. yone or.e.y , = m ! 3. ue e. .euse e cona n. n-h* ' o- , <. / sJi.s l I J J
- 4. m._
- t n. m u .. _ /A,w
~b i tsi,.ene.enn.,,enment,.e,oneus.
4 gNG ; p j u J '
/
l , j on,enme= Nous w C.$wFnhAr one D. , e. ,, t. . se, % u,
- y~. ,
i REVIEW / APPROVAL ;
- 1. Aeolenee Deparwnennunmet ___- ; 'E!!%! ,
3r;Jpy/pfeiftynne 7) yy
- E z nousne Nes v m [ E Ner era Ova E W ps.ress . hew sea. 7s
- E 3. N ,.roO o N Arar<,.a Aer5 A f.r l 4. Evaluesen due byh, /1 FGr.ceve maneures iI
#MN compiated h Y
&qW D. -* r . .so, m no l
- 1. Nognandone. 0.e AP 0910731,'NRC Regaired Non Roulho Noglamaans & Reports
- Yes O No AP 0005732,' Plant Guide to Repor9ng Enwhenmental ;&Ah and Slenmcarn EweneP q 1 eP 0oostas, pepor ng or amfeguense events")
Q . event TWm 14 j
- s. securarevent Yne No O FOP INE signenne nem )
- i. = epe,eine r ==o== neessai consnuessp esen, O va ONe
& Does mis leers put us k en endan stuenentt Yee No 11mu@ste J Duradon
- 8. Does ele born dedere a system er component 0067 Yes No Whatequ5mert
- 4. Wheilmmedeep noGNoeGens were made, (NMO, EPA. et$
_ am e- O va y ~,p6 6 6"5 6 6
- e. Amen.nwcommentvenneman.
/
rensue oen p.ss amwPtp poor.o.rpseg
. _ _. _. 7; y 3._.-.__g . ;. 7 1 1 -a imeene i
~~ ' ' ' 5 ' r# -- -'
WwmAankhne. '
~-
j l .
- *ngineering .
! A, of a non conforming nom le in q'astion and conenemd opension le reqJred. - O s. ansineerino evidea= le required 'or reste:='oa a' desica-i c. anoineerino assionence needed for root caum deienninesion. . O o. Por sesear reieiedlaussir reiemed a me. past Per=bsier a'iism ie auesiioaebie ces 8=und condisoro. ! O u. soeveiuemenioneeded. OP iocevisi issue Todinleal
- 1
' w. AsMexiieous O a.so.seiseu. '
- 11 any block (A twough H) is chooked, enower the fonowing I
f Resoluden tequired. Date . 1 f , Mode , e ) coraggonalreleese to use esle Oves O No (supporting documertadon requhed) j ,- Dispostlenedby _ vertried by - l ANilfWow 183 RevioW IrWoollgellorVRoot causelGeneric impaal/How to Preen ResponstWePerson 4 &aeW6 { l LE em m r. A k k.r;r ceA*, 4.e enhaf 4 _. h e /on L2 \ in a ! nd UL 2# s, J .. \ L. aA w *'*'. '
- v. a u
! 5 4. C L 1 4 r .=c.4s .,,.m.- . c mr 4 t- owinge veniese uses cornpimed , Ase10 ned to Required (PCM, NPWO, PCR. Deep l 'orrective Actions SNOW REF l
- 1.mu .L M 6.t w f f O ar s e.v h k b i --
t L w it~ l
- 2. .
I 1- 0 0 J J-l S. J )_ 0 ,) I_ t l I Note: Cerromve entione are is also include rg special reports required (LER. NCN sosponses. NP=700, ets.) l { y " m aJTsevin.m
- 1. AE conoceve odione complete (note excep6cne below) f Assigned Departnant l
2.' Inldal1 DepartnantConcunence f inilledn0 Department l. i 3. QCC.innunence 1 QC 1 4 PjentGeneral ManagerConcurrence i Plant General Mano0er
- ,n ; easons essereenery and -e ey.ed in) sign aste onw I
Ennertme: 1 i ( ". 1 1 -
't f*lW M)
' 4 i i
> ,;! : :!:;llf :tlii!' !![i!liltfii
_ l[! t u%JEI!jtii! i t$ yi [ ;; 3 g3# [ i. s h" @" SU >b t t - 3 dyggu" .* g g. _ > 2 E D O _ 5 V R Y T I N: TA _. 9F
/O L
A ED'r T _ REr I M E O E . 5 11 V UTt sir J L I FOT RE ME SBE AEP tO N .T t _ / F E SM EIw B EFS Y cI L P 8p ITRL.RP A I L .S DGCESVI LSSEE F . LEP EG TAS RC ARA & E RCL SII NNTEL U R IL If RATO . Y TS OEHNmS 'E REOEA
/HT HO(HPVBI TIGRER . K CE ,IS II
_ T HDLC ST SSO,R W _ EETK FEF 2 EIA SAI LHEGP RET .CEDBBO NC. NT t _ _. ABIiUE IR SALE BS, TY LTGDN AI t WhTI IS G.EG I NEFTBE E F HTG DT P O. ,B _ TG OrCER iBOS C G _ _ M L)TPX; EN N SA OO EY DI D EEENP t fAP M M ,U tB X _ OIt FIE I
,. C IETE EENG IPiNE T AR X V CRID V MIT NVR N G WTYGTI TL AS 1DM RR RE I IRr OS2 OSCG A tFA 2
I DRLIR Ai IPRU P I . P DEMiMIW TT SEIG C X SVM TGDWTPNI m ,OQOR RO I R C EI TP(S1 iAs r C V IOImGA Si t ER .M _ S rrLR r APOmK B SE,t ECU ,IX
.- /WTDiIS T M N -
Oi ,A C p I _ C-I OCUI OABWF TI NIQSI ROo A V.eN)N I _ Z TNI A O GA,IE I SNC ECrE RRIA E AEN PH S" TtT EGO I LOX; _. I I AC% E URL . E G LMRNCN5 R PI E9s IW TS AGRS. NSDE STB S BC (TECT VIN 3 E . TTB RRV EE IT , ,DM , ,S I _ X T ESDAS NEE R .N NRSE EE
.E E M ? C l
t E I IRZRHiTOS E t c R t BT tGC A CIM"SF ENRIKTSG E E D* I (* OP DEA I G 4+ ASM I EWAEtD GTO (BTID M IEE X N ER W SV D thP RBICO .EA t UAOSLI G E EEATsD P EtIE l n ELELD E CD e @r E IT E R RNSR m m u X XmCABBFF C PDDSAR ONEhEO E IAI P P f OVTO
~
C IOE L Mt s oPLHNMER VET EIB ISS MWEI ETIL SV P L
@gWgs adN .
g Etu Er EPU E C Sr N See NO EG I A N r Em I/ R ro s 3 {A R B E E Lr V Aa a FT SP
. T N
I N E hnWL t I E [ t EEE e f Vmn RI R g W.- _P o t ru u 1 T gb s i K T. y NN h t VS Rs IE M.P . L eVE E r. o 4mE 3 2 X Si o SP Et 1 i RI E p 02I K EN IC O
# wS r 5 P Is PD Pf c 9BID N Rs O
[S b DD a 0AE C I f Ra EO EP P 9 1U R I @T I S EI VS C VI 6 . RI C Cn EA RLQ A Os IB % EK IS TSE . . . SPE 1 2 3 [ hL
Ef .I I P.2&2 g e- l 8 B
.i : .
ACEECK ..:..c.,. - rumrWTPf15 9 IMPF,/WOUP b u b..t
- 4. PRIMITIZRTIN MkINIENAN 3 PRINITIZE VALVES TO BE REVIEMED & SCHEEEE FOR $
OF REMI9f C0t@iETIN OF ERG PHASE.10IB: PRIORITIDfPIN 3; OF REVIEN IS BY SYS11 INS; SDC, HPSI, APW, ErtC. . . [ t# ev
- 5. REVISE PLANP MAINIENANGE/ REVISE AOMINISTRATIVE, MPJNIENANCE, ADO QI PROODLRES 'IO r- ;
PIOCEDORES TEN STAFF INO3tPORATE ANY RECDMiMDED SRV GANGES RESILTING PRm 8! DESIN BASIS REVIEN. El w MAINIENANCE REVISE MPGNIENAME PROOD(RES 'IU INCIRPCRATE USE OF NEN 3i TEST BENCH. 2!
"r a
i o;
- 6. EBRERNCE M/M TRAINING INERN0t JD(ENilYMRN TRAINING PROGRAM N BRr.TRP VALvas As ?l J0(EBEDEN DESCRIBED IN TahR DRSED 4/12/95. AS A MINIMM, 'IRAINDU ;; '
, 1Ranmo arouro nrnrm ImONSWATIN OP IAPPING SImL
- PROPI(mBEY, IrmtrR RDG SEITINGS, AND Urff.TEATIN OF THE Mill TEST BENT. ,
I r f
?
I"* b 4 r 13' . t "U
*?
. 81 h
I f
r 11-do-1:':0 12Wrt bt w ete hes.oent i.htice ~ ~ ~~~" ~ M r 4o1~ 4hbr - -- - -- v.we ~ -- ST.LUCIE ACTION tst m REPORT sTAne WMU geneyp i,g_
.-[ .meWin rCAiiG# foIsii46 1 1
- 1 ; r irsdeena MM 'O'f p pc,J/ l Desortptkx1 g
- e. ~ = nu u , , ,
p-, n~.c t:c = 1 n ,..,
,.opy r's-, ru. 2/J Ar< .b L = ' a.
.n _
-sll.en r.4. e % +
0""P'""" 80 "# A -: ne m / ~> > w < x ... - t'c A J ',.~r ar a:r t m . 7
, mh eL L ,A .. indMdualNamhd us m . ~ ,A )~,y 1 hm . Jr . _ _ _
l n ,... % __,_.. _ taanden u r m en' n . . r% r ces n u e .. . -a m g NRC tugubn 9. Auf.nspen, Operemrwonnenund O von O n. j --
~ -
8.personnelobservueen, em.)
~_m I C. _ T. o n._._, ,Y O- ASMH XI a
~e-- et / -- = ' . ~ -3
- s. whatweresayandwasmersuomessur
-r-. v. -- - %g mt,
~_-_...~ , -
* . . J e. L m wc ier . , < . asm.v- es. /,I ee m_. - ,
*I c:' car-+ m
- % = -e '
- s. auspemed emuss etennesen. m - . '
ca.,- -,,i w . . c.~ es v A A ~
- 4. naamsensmessenmenneetandesp.enentmasonsade.7-.--- / um - -c; w n= p .
z,m .~- -.a -ww <~ n n ....o. nA DerbHead _ agr-W [bM N Doyouhappnmdtodoset G E, '
@Y== 0 No f-RE%ceV/ APPROVAL
~V-
,, sadened n z.~ w Srser / .o. sva r
- a. noudr , NPs O vos p sT4 0 vos D d8o
- s. NP490 0 NPus O 1
- 4. Ewiussenaustry Mi /31Iconocawrnessweesongdsendby /_
TMub /TIF!ffDoyourequs.eppmWmatmet 9*6 O No
- 1. atagiadens. (La AP0010721 Arnoosm. NRC Required, No.n.R.oudre.NeWisodens pumaumen. en ne .d m. m .ns.Oem O a
& Ruper=-.nemenw none eromootas, meporensetassepeeewn.-)
g j
- 2. IhersType 14 are== ===
- s. asauey ment Yes No FQP O ine
- 1. Isopenemy=====amersneededterannenuedsporensn' O von ONo Yes No TbnetDens f Dureden
- 2. Does eds tem put us in en amien summert?
- 3. DoesedstemesclareaeyseemercomponertOoer O vs. O a= va=neauipmer- ,
I y 4. whet kenedisso nassandens wero manet (Nne, upA. ese E 6 h" 6 f E. Is emm amoon haast Om M Priorin6 6 6
- 5. Adstonalenmmeneteadoneashen.
/
! agnumse uses Otsv.0-7/799 i (Ol48 80LWPG) l
- CLOSING REMARKS
- (S. Ebneter) a In closing this predecisional enforcement conference, I remind the Licensee of two things:
A First, the apparent violetiens discussed at this predecisional enforcement conference are subject to further review and may be subject to change prior to any resulting enforcement action. l Second, the statements of views or expressions of opinion made by NRC employees at this predecisional enforcement conference, or the lack thereof, are not intended to represent final agency determinations or beliefs. l
l "
?
FM - UNITED STATES NUCLEAR REGULATORY ! I COMMISSION l 4* 0 i l ST. LUCIE PREDECISIONAL ENFORCEMENT CONFERENCE . SEPTEMBER 25,1995 q i
.p N
.i AC he$" $ N Y*~
' M $ $ f ,/7
- J (,4p .* g,
- e 2 i
$ W S-
"5Y f , lg Y
' ,&ut w su.4.:up.,
] )fn.e/ vn,as dce,-w ndlVIw- i 4 dry,h/
, '3 y ,; wHg ;,p Y $4 '" ,M,P x v .m, J ' Qli ' nrpp;)- t%T p~pJ(' .
.1
-fy _ llr , ilb&p ;?s' rat.I
* /r?!do
(,,An + cL d- ' G.~%~s'sL-
+& L i par ,,J au+ zf4 /f NRC CLOSED PREDECISIONAL ENFORCEMENT CONFERENCE ST. LUCIE NUCLEAR PLANT.
SEPTEMBER 25,1995 I
f PREDECISIONAL ENFORCEMENT CONFERENCE AGENDA ST. LUCIE SEPTEMBER 25,1995, AT 10:00 A.M. , NRC REGION ll OFFICE, ATLANTA, GEORGIA j i
- 1. OPENING REMARKS AND INTRODUCTIONS :
S. Ebneter, Regional Administrator l V l
- 11. NRC ENFORCEMENT POLICY I B. Uryc, Director Enforcement and Investigation Coordination Staff Ill.
SUMMARY
OF THE ISSUES S. Ebneter, Regional Administrator
! i 4
IV. STATEMENT OF CONCERNS / APPARENT VIOLATIONS ) E. Merschoff, Director l Division of Reactor Projects i V. LICENSEE PRESENTATION W. Goldberg, President
'St. Lucie Nuclear Plant VI. BREAK / NRC CAUCUS Vll., NRC FOLLOWUP QUESTIONS Vill. CLOSING REMARKS S. Ebneter, Regional Administrator
/
l l lSSUES TO BE DISCUSSED
- 1. 10 CFR 50, Appendix B, Criterion XI required, in part, that a test program be established to ensure that all testing required to demonstrate that components will perforrn satisfactorily in service be performed and that the program include proof tests prior to installation. FPL Topical Quality Assurance Report TOR 11.0, revision 4, " Test Control," stated, in part, that a test program shall be established to assure that testing required to demonstrate that structures, systems and components will perform satisfactorily in service and that the program shall include proof tests prior to installation.
In November,1994, valve maintenance was performed under a work package, which directed the rebuilding of Power Operated Relief Valves V-1404 and V-1402 per licensee procedure 1- , M0037, Revision 6, " Power Operated Valve Relief Valve l Maintenance. The post-maintenance testing was limited to a bubble test for seat leakage prior to reinstallation. The procedure contained a note explaining that lift set point testing was not required, as the valve was lifted based upon solenoid valve input. The procedure did not require a verification that the valve would change state under pressure prior to installation. 1 l l l NOTE: The apparent violations discussed in this predecisional enforcement conference are subject to further review and are subject to change prior to any resulting enforcement decision. l 4
ISSUES TO BE DISCUSSED 2
- 2. 10 CFR 50, Appendix B, Criterion XI required, in part, that a test program be established to ensure that adequate test instrumentation is available and used. FPL Topical Quality j Assurance Report TOR 11.0, revision 4, " Test Control," stated, in part, that a test program shall be established to assure that testing required to demonstrate that structures, systems and components will perform satisfactorily in service is performed and that the program shall include operational tests. TOR 11.0 further states that test procedures shall incorporate requirements and acceptance limits in the applicable design and procurement documentation.
On November 25,1994, and on February 27,1995, operational surveillance testing, performed under Administrative Procedure 1- ' 0010125A, revision 39, Data Sheet 24, did not employ adequate test instrumentation to detect the inoperability of both valves 'and l did not employ test acceptance limits derived from the valves' design documentation. Specifically, the use of acoustic data, as opposed to system pressure reduction derived from valve capacity, to indicate valve position was insufficient to discern the l difference between bypass flow through the PORV pilot valves ! and actual changes in main valve position. NOTE: The apparent violations discussed in this predecisional enforcement conference are subject to further ' review and are subject to change prior to any resulting enforcement decision. i 4
j -
- 1 l- .
I j ISSUES TO BE DISCUSSED i 0 l I [ 3. Technical Specification 3.4.13 requires, in part, that two Power 3 [ Operated Relief Valves be operable in." Mode 4 when the j temperature of any RCS cold leg is less than or equal to 304 F, y i Mode 5 and Mode 6 when the head is on the reactor vessel; and ; l the RCS is not vented through a greater than 1.75 square inch l i vent." TS 3.4.13 AS (c) required that, "with two inoperable ,
- PORVs, at least one PORV be returned to an operable status or !
! that the RCS be completely depressurized and vented through a' l [ minimum 1.75 square inch opening within 24 hours." l
- . l
- crom November 22 through 27,1994, and from February '27 4
.through March 6,1995, St. Lucie Unit 1 was in conditions
- requiring operable Power Operated Relief Valves but no operable .
1
- relief valves were in service'. The inoperability of the Power j- Operated Relief Valves resulted from a combination of personnel ;
j error during maintenance and inadequate post-maintenance and ! j surveillance testing. I i j !. l 1 i NOTE: The apparent violations discussed in this predecisional enforcement conference are subject to further review and are subject to change prior to any resulting enforcement decision. i l l I l i I i
I l NRC CLOSED PREDECISIONAL ENFORCEMENT CONFERENCE ST. LUCIE NUCLEAR PLANT SEPTEMBER 25,1995 l
)
IAB TITLE 1 Predecisional Enforcement Conference Agenda 2 Expected Attendees, Meeting Announcement l i 3 Opening Remarks and introductions 4 NRC Enforcement Policy 5 Summary of the Issues l 6 Statement of Concerns / Apparent Violations i 7 Inspection Report No. 50-335/398/95-16 i i 8 Enforcement Pre-Panel Questionnaire 9 50.72 Report, LER 95-238 l 10 Closing Remarks: J l 1 l i
t PREDECISIONAL ENFORCEMENT CONFERENCE AGENDA ST. LUCIE SEPTEMBER 25,1995, AT 10:00 A.M. NRC REGION 11 OFFICE, ATLANTA, GEORGIA 4
- 1. OPENING REMARKS AND INTRODUCTIONS S. Ebneter, Regional Administrator
- 11. NRC ENFORCEMENT POLICY B. Uryc, Director Enforcement and Investigation Coordination Staff
~
111.
SUMMARY
OF THE ISSUES . S Ebneter, Regional Administrator IV. STATEMENT OF CONCERNS / APPARENT VIOLATIONS E. Merschoff, Director Division of Reactor Projects V. LICENSEE PRESENTATION W, Goldberg, President-i St. Lucie Nuclear Plant . 1 VI. BREAK / NRC CAUCUS
- Vll. NRC FOLLOWUP QUESTIONS ,
Vill.. CLOSING REMARKS S. Ebneter, Regional Administrator 1 l 4
________.___q i I i EXPECTED ATTENDEES
- l i
Licensee ' l i J. Goldberg, President, Nuclear Division D.-Sager, Vice President, St. Lucie Site l . W. Bohlke, Vice President, Engineering l l L. Bladow, Nuclear Assurance Manager
- D. Denver, Site Engineering Manager !
; L. Rogers, Systems and Component Engineering Manager l
- J. Marchese, Maintenance Manager J. West, Operations Manger I
NRC Stew Ebneter, Regional Administrator, Region II (Rll) 9 Ellis Merschoff, Director, Division of Reactor Projects (DRP), Ril : Al Gibson,' Director, Division of Reactor Safety (DRS), Ril Bruno Uryc, Director, Enforcement and Investigation Coordination Staff (EICS), Ril Charles Casto, Chief, Engineering Branch, DRS, Ril ! l Kerry Landis, Chief, Reactor Projects Branch 2, DRP, Ril i Linda Watson, Senior Enforcement Specialist, EICS, Ril i Carolyn Evans, Regional Counscl, Ril , i Richard Prevatte, Senior Resident inspector, St. Lucie, DRP, Ril l Robert Schin, Project Engineer, Reactor Projects Section 28, DRP, Ril l . Edwin Lea, Project Engineer, Reactor Projects Section 2B, DRP, Rll ) l George Hopper, Operator Licensing Examiner, DRS, Ril i I T 4 I l i l l l
l I l OPENING REMARKS AND INTRODUCTIONS l . (S. Ebneter) 4 Good morning. I am Stew Ebneter, Regional Administrator for the l
- Nuclear Regulatory Commission's Region 11 Office. This morning we j
. will conduct a predecisional enforcement conference between the NRC
- and St. Lucie which is CLOSED to public observation.
i. The agenda for the conference is shown in the viewgraph. Following
- my brief cpening remarks, Mr. Bruno Uryc, the Director of the Region ll Enforcement Staff, will discuss the Agency's Enforcement Policy. I 1
will then provide introductory remarks concerning my perspective on l the events to be addressed today. Mr. Ellis Merschoff, Director of the
- Division of Reactor Projects, will then discuss the apparent violations.
You will then be given an opportunity to respond to the apparent j ^
)
violations. In this regard, I wish to reiterate to you that the decision to
- i
. hold this conference does nct mean that the NRC has determined that viclations have occurred or that enforcement action will be taken. This conference is an important step in arriving at that decision. l
5
. I L
Following your presentation, I plan to take about a 10-minute break so e that the NRC can briefly review what it has heard and determine if we 1 have follow-up questions. Lastly, I will provide concluding remarks. ! At this point, I would like to have the NRC staff introduce themselves ! i and then ask you to introduce your participants. E [lNTRODUCTIONS1 , Thank you. l l Mr. Uryc will now discuss the Agency's Enforcement Policy. f I
1 i
\
. NRC ENFORCEMENT POLICY a (B. Uryc) i NRC Enforcement Policy and Procedure i After an apparent violation is identified, it is assessed in accordance with the Commission's Enforcement Policy, which was recently revised I J ! and became effective on June 30,1995. The Enforcement Policy has ; i been published as NUREG-1600. j i-
]
The assessment of an apparent violation involves categorizing the apparent violation into one of four severity levels based on safety and i i
. regulatory significance. For cases where there is a potential for i escalated enforcement action, that is, where the severity level of the
.apparcit violation is categorized at Severity Level I, ll, or Ill, a i i l- predecisional enforcement conference is held. l
)
i There are three primary enforcement sanctions available to the NRC and they are Notices of Violation, civil penalties, and orders. Notices
.of Violation and civil penalties are issued based on identified violations.
l Orders may be issued for violations, or, in the absence of a violation, i because of a significant public health or safety issue. .
. _ _ . - . _ _ . __ _ ._ ..__- _ _ -__ - . ~ _ _ _ . . . . _ . _ - . . This predecisional enforcement conference is essentially the last step of the inspection or investigation process before the staff makes its final enforcement decision.
'The purpose of this conference is not to negotiate a sanction. Our ;
purpose here today is to obtain information that will assist us in determining the appropriate enforcement action, such as: (1) a common understanding of the facts, root causes and missed opportunities associated with thehko/ lations, (2) a common understanding of corrective action taken or planned, and (3) a common understanding of the significance of issues and the need for lasting comprehensive action. fptd f** A LA The apparent violations discussed at this conference are subject to l further review and they may be subject to change prior to any resulting enforcement action. It is important to note that the decision to conduct this conference does not mean that NRC has determined that a violation has occurred or that enforcement action will be taken.
I should also note at this time that statement of views or the expression of opinion made by the NRC staff at this conference, or the lack thereof, are not intended to represent final determinations or beliefs. Following the conference, the Regional Administrator in conjunction with the NRC Office of Enforcement and other NRC Headquarters offices will reach an enforcement decision. This process should take about four weeks to accomplish. Predecisional enforcement conferences are normally closed to the l 1 public as is this conference. However, the Commission implemented a i trial program in July 1992 to allow certain enforcement conferences to be open for public observation. [ July 10,1992 - Federe/ Register) This trial program was recently extended for additional evaluation. i Finally, if the final enforcement action involves a proposed civil penalty or an order, the NRC willissue a press release 24 hours after the enforcement action is issued.
i
SUMMARY
OF THE ISSUES (S. Ebneter) Issues: St. Lucie Power Operated Relief _ Valves inoperable i I Power Operated Relief Valves V-1404 and V-1402 were reassembled incorrectly and did not receive adequate post-maintenance testing. The PORVs were reinstalled in the Reactor Coolant System on November 5,1994, without adequate surveillance testing sufficient to provide reasonable assurance that the valves would perform their intended function while in , service. Defect: As a result of the inadequate reassembly, post-maintenance testing, and surveillance testing the PORVs were inoperable from the time they were installed in the RCS during the 1994 refueling outage until they were removed and reworked in August of 1995. Plant data indicated that the valves could not have performed I j their intended safety function. Plant data also indicated several
o , 4 2 ^ p instances in which an operable PORV was required by TS, but ; i > ! was not available. . i
; i I
- i 4
i 1 , \ Consequences: i ., i i a ! ' Inoperable-equipment was installed in the Reactor Coolant System
- , which was unable to perform intended' safety function.
4 i d .- e 4: 4 4 N f 1 J I i I < i i I i
. . -- - .=. . - . . . - - --. .- ~ -- . -- - -
d l STATEMENT OF CONCERNS / APPARENT VIOLATIONS l (E. Merschoff) l 1 u This is a Predecisional Enforcement Conference to discuss three : '.. l apparent violations associated with PORV maintenance and operability. ^ i The first and second apparent violations involve the ade.quacy of the ! procedure used to perform post-maintenance testing and the ' l procedure used to perform surveillance testing. The third apparent l 4 j violation addresses the operability of the PORV as required by TS. We are concerned with those activities which resulted in the PORVs - J being rendered inoperable. Encompassed in our concerns are the facts ] 4
)
l that post-maintenance and surveillance testing should be of sufficient i i scope, and acceptance criteria of sufficient technical rigor, to ensure i component operability. We are also concerned with the consequences i , of operating outside TS limits, due to inoperable PORVs.
- Yc l N4
' mr r gef,# ) i l i l 6xf l j
+ .
- i i
l
t l l 7 i i
)
F Our findings are documented in NRC Inspection Report 50- ;
- i. . l j- 335/389/95-16, which were transmitted to you'on September. 8, 1995.2At this conference, we are affording you the opportunity to 4
provide information relative to: L 4 1
--- Any errors the inspection reports i
?
--- The' severity of the violations '
--- Any escalation or mitigation considerations l
--- Any other' application of the Enforcement Policy relevant to this issue.
i
ISSUES TO BE DISCUSSED
- 1. 10 CFR 50, Appendix B, Criterion XI required, in part, that a test program be established to ensure that all testing required to demonstrate that components will perform satisfactorily in service be performed and that the program include proof tests prior to installation. FPL Topical Quality Assurance Report TOR 11.0, revision 4, " Test Control," stated, in part, that a test program shall be established to assure that testing required to demonstrate that structures, systems and components will perform satisf actorily in service and that the program shall include proof tests prior to installation.
In November,1994, valve maintenance was performed under a work package, which directed the rebuilding of Power Operated Relief Valves V-1404 and V-1402 per licensee procedure 1-M003'7, Revision 6, " Power Operated Valve Relief Valve Maintenance. The post-maintenance testing was limited to a bubble test for seat leakage prior to reinstallation. The procedure contained a note explaining that lift set point testing was not required, as the valve was lifted based upon solenoid valve input. The procedure did not require a verification that the valve would change state under pressure prior to installation. NOTE: The apparent violations discussed in this predecisional enforcement conference are subject to further review and are subject to change prior to any resulting enforcement decision. l l 1
i I ISSUES TO BE DISCUCSED i i l
- 2. 10 CFR 50,- Appendix B, Criterion XI required, in part, that a te'st i program be established to ensure that adequate test l instrumentation is available and used. FPL Topical Quality i Assurance Report TOR 11.0, revision 4, " Test Control," stated, in '
part, that a test program shall be established to assure that testing required to demonstrate that structures, systems and components will perform satisfactorily in service is performed and
- that the program shall include operational tests. TOR 11.0
- further states that test procedures shall incorporate requirements and acceptance limits in the applicable design and procurement ;
l documentation. On November 25,1994, and on February 27,1995, operational surveillance testing, performed under Administrative Procedure 1-
- 0010125A, revision 39, Data Sheet 24, did not employ # adequate test @*rtm"' ato detect the inoperability of both valves and '
i did not employ test acceptance limits derived from the valves' design documentation. Specifically, the use of acoustic data, as
- opposed to system pressure reduction derived from valve j capacity, to indicate valve position was insufficient to discern the difference between bypass flow through the PORV pilot valves and actual changes in main valve position.
- NOTE: The apparent violations discussed in this predecisional enforcement conference are subject to further review and are subject to change prior to any resulting enforcement i decision.
p p ., urc . 4 5. E =cf f u~ wW9?' 3 , ge " 6/ e# i
- - _ - . _ .- ._ - ~_. - _ . .- - .
ISSUES TO BE DISCUSSED 0
- 3. Technical Specification 3.4.13 requires, in part, that two Power-Operated Relief Valves be operable in " Mode 4 when the temperature of any RCS cold leg is less than or equal to 304 F, Mode 5 and Mode 6 when the head is on the reactor vessel; and the RCS is not vented through a greater than 1.75 square inch vent." TS 3.4.13 AS (c) required that, "with two inoperable PORVs, at least one PORV be returned to an operable status or that the RCS be completely depressurized and vented through a
- minimum 1.75 square inch opening within 24 hours."
i From November 22 through 27,1994, and from February 27 i through March 6,1995, St. Lucie Unit 1 was in conditions ! requiring operable Power Operated Relief Valves but no operable } ~ relief valves were in service. The inoperability of the Power Operated Relief Valves resulted from a combination of personnel error during maintenance and inadequate post-maintenance and surveillance testing. NOTE: The apparent violations discussed in this predecisional enforcement conference are subject to further review and are subject to change prior to any resulting enforcement decision.
l
- 1
\
e j From: James Kreh / /f 2- l To: ATB A docna o, 2 c ) Date: 11/7/96 2:46pm ;
Subject:
ST. LUCIE EAW . l As we discussed, Dan Barss will be E-mailing his input on items 5 and 6 to you for i incorporation into the EAW. Feel free to call me at home tomorrow if you just can't figure it out. Good luck! CC: KPB i l I l 1 I i 1 1 i f (4 n ,. , - l 7 \ U M ClO O M'$
o 1 ENFORCEMENT ACTION : WORKSHEET ' l BREAKDOWN IN MANAGEMENT CONTROL 0F THE , ST. LUCIE EMERGENCY PREPAREDNESS PROGRAM ; l PREPARED BY: James L. Kreh DATE: November 7. 1996 1 This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. l Signature 1 Facility: St. Lucie Plant , Units: 1&2 ' Docket Nos.: 50 335, 50 389 License Nos.: DPR 67, NPF 16 l Inspection Report No.: 96 18 ' Inspection Dates: October 7 18 and October 28 November 1, 1996 Lead Inspector: J. L. Kreh
- 1. Brief Summary of Inspection Findings:
Violation A I On the evening of October 3,1996, the licensee conducted a test of its automated system known as the FPL Emergency Recall System (informally called " autodialer") for notifying the emergency response organization (ER0) in the event of an off-hour emergency requiring augmentation of the on-shift crew for staffing and activation of emergency response facilities (viz., Technical Support Center [TSC]. Operational Su3 port Center [0SC]. and Emergency Operations Facility [ EOF]). The autodia~ er did not operate, and no individuals received notifications during the test. A failure assessment by the licensee disclosed that the autodialer had been in an inoperable configuration for a period which apparently began on July 22. 1996. In addition, the inspection identified the licensee's failure to adequately maintain the manual backup system (a " call tree") for ERO call-out over an indeterminate period (at least the last several years). These concurrent deficiencies represent a failure (during the period July 22-October 3,1996 at minimum) to maintain the capability to execute the provisions of the REP and its implementing procedures in a timely manner with respect to mobilization of the ERO during off-hours. PREDECIsIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
j ENFORCEMENT ACTION 2- .
- , WORKSHEET
- Violation B i The . licensee's training program for ERO personnel has not been adequately
- implemented since at least.1994. This violation includes failure to :
provide opportunities for most personnel to participate in exercises-3 and/or drills, failure to provide annual retraining to certain designated aersonnel in 1994 and 1995 failure to provide any training for certain ERO positions with respect to selected implementing prc edures, and a failure to remove individuals from.the ERO roster when their respirator qualifications had lapsed. ;
- 2. Analysis of Root Cause:
~ The root cause of both violations is failure of licensee management to . (a)-provide an appropriate level of oversight of the emergency i preparedness program as required by the . REP, and (b) ensure the implementation of timely and effective corrective actions for identified findings and deficiencies in emergency preparedness.
- 3. Basis for Severity Level (Safety Significance):
For both violations: Sucolement VIII - Emeraency Preoaredness. SL III ; Section C.3 of Supplement VIII- presents as an example, " Violations involving ... a breakdown in the control of licensed activities involving. ! a number of violations that are related . . . that collectively represent a l potentially significant lack of attention or carelessness toward licensed responsibilities. Section IV. A of the Enforcement Policy states that "a group of Severity Level .IV violations may be evaluated in the aggregate and assigned a single, increased severity level, thereby resuting in a Severity Level III problem, if the violations have the same underlying cause or programmatic deficiencies, or the violations contributed to or were unavoidable consequences of the underlying problem."
- 4. Identify All Previous Escalated Actions Within 2 Years or 2 Inspections
> 95-180: PORVs Inoperable Due To Personnel Error: SL III
- 96-040: Dilution Event: SL III
> 96-249: Multiple Examples of Inadequate 50.59 Reviews: SL III
- 5. Identification Credit? No Violation A I Date licensee was aware of issues requiring corrective action:
October 3. 1996. This identification credit /date applies only to the autodialer inoperability portion of the violation. The problem with the manual call-out system was NRC/CI-identified. i PREDECIsIONAL ENFORCEMENT INFORMATION . NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
i - lj ENFORCEMENT ACTION 3- 1 WORKSHEET-l Explain application of identified credit, who and how identified and consideration of missed opportunities: The inoperability of the autodialer was identified by the licensee on 10/3/96, but could have been identified much earlier if periodic functional tests (e.g., weekly) had been performed. With appropriate administrative controls in place (as had been recommended by an EP - Coordinator as early as April 1996), autodialer inoperability would have I almost certainly have been precluded. An autodialer problem (limited in i scope--not a complete system failure) also occurred during the NRC-l evaluated June 1993 exercise, but corrective actiori for that problem was , clearly not sufficier,tly comprehensive. ' , 6. Corrective Action Credit? No Violation A ! Administrative controls have been implemented for the autodialer under i Protective Services Department Guideline No. PSG-015. " Maintenance and l Testing of the Emergency Recall System", Revision 0. dated 10/29/96. For the manual call-out system, individuals required to maintain a copy of the l procedure were added to the controlled distribution list, and a drill was conducted on October 10, 1996 with reasonably successful results. ! Application of-corrective action credit: (1) No credit for autodialer i issue because identified by licensee EP Coordinator in early 1996 and no l action taken: (2) Credit for correction of manual call-out problem after 1 identification to licensee on 10/7/96. ' Violation B
- 7. Canaidate For Discretion? No
' Licensee's performance in emergency preparedness is now recognized to have been particularly poor during the past several years.
- 8. Is A Predecisional Enforcement Conference Necessary? Yes Why? To determine whether the subject violations represent a programmatic breakdown in emergency preparedness.
If yes. should OE or OGC attend? Yes i l Should conference be closed? No - l 9. Non Routine Issues / Additional Information: ; ! i 4 l i PREDECIsIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
i l ENFORCEMENT ACTION 4-WORKSHEET. OTHER FINDINGS FROM THE OCTOBER 1996 EP PROGRAM INSPECTION Violation i
' Failure to establish an Emergency Plan. Implementing Procedure (EPIP), or i to have an adequate EPIP, with appropriate implementing details to address !
certain aspects of the Radiological Emergency Plan as follows: , i
- a. the transfer of OSC functions to an alternate location in the event l that evacuation of the primary OSC is required (EPIP-3100032E, "On-site Support Centers", contains no implementing details for the statement in Radiological Emergency Plan Section 2.4.4 that "In the event that the OSC becomes untenable. the Emergency Coordinator will desic1ateanalternatelocation."){inadequateprocedure},and
- b. recovery activities upon reaching a stable plant condition following ,
an emerg ncy (Radiological Emergency Plan Section 5.4) {no i procedure . ) Emeroency Preoaredness Proaram Weaknesses
- 1. Inadequate p ogram of drills to ensure availability of sufficient ERO personnel and timeliness of ERF staffing !
- 2. Management failure to ensure the implementation of timely corrective actions for certain emergency preparedness deficiencies and weaknesses. Examples are:
i
- a. failure to address concerns regarding the audibility of the Gaitronics (or plant public-address system) formally 1 identified in late 1994 and still being tracked as an open item by the licensee's corrective action system,
- b. failure to provide adequate corrective action to address a questionable capability for notification of the State of Florida within 15 minutes of an emergency declaration (identified by an NRC inspection in February 1995), and
- c. failure to implement timely corrective actions for deficiencies and recommendations identified by the critique of the Hurricane Erin response in August 1995 (examples of issues: identify hurricane-safe structures onsite and a plan ;
for positioning personnel in those structures: designate an onsite individual to monitor the hurricane path; establish consistent staffing policies) i i
- 10. This Action is Consistent With the Following Action (or Enforcement l Guidance) Previously Issued: l
[ Supplement VIII. Sec. tion C.3 l l l
\
l PREDECISIONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC i RELEASE W/0 APPROVAL OF DIRECTOR, OE i l l
=
ENFORCEMENT ACTION 5
< WORKSHEET. f
- 11. Regulatory Message:
Management must provide strong and consistent oversight and support for emergency preparedness activities in order to ensure a viable emergency I response capa9111ty at all times.
- 12. Recommendeci Enforcement Action:
Two SL IV violations evaluated in the aggregate as a SL III violation
- 13. Should This Action Be Sent to OE For Full Review? No
- 14. Exempt from Timeliness: No.
Basis for Exemption: N/A Enforcement Coordinator: DATE: l T PREDEtis10NAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
s ENFORCEMENT ACTION 6-4 WORKSHEET DRAFT NOTICE OF VIOLATION St. Lucle Plant Inspection Report Nos. 50-335, 50-389/96-18 A. 10 CFR 50.54(q) requires that nuclear power plant licensees follow and maintain in effect emergency plans which meet the planning standards of 10 CFR 50.47(b) and the requirements in Appendix E to 10 CFR Part 50. Section 2.4 of the licensee's Radiological Emergency Plan (REP). Revision 31, states that activation of the Technical Support Center (TSC) and the Operational Support Center (OSC) will be initiated by the Emergency Coordinator in the event of an Alert. Site Area Emergency, or General Emergency, and that arrangements have been made to staff the TSC and OSC in a timely manner. Also specified is that activation of the Emergency Operations Facility (E0F) is required for a Site Area Emergency or General Emergency, and that arrangements have been made to activate the EOF in a timely manner. The REP requirements delineated above are implemented by procedure EPIP-3100023E. "On-Site Emergency Organization and Call Directory". ; Revision 72. The instruction in Section 8.2 of that procedure states 1 that, upon the declaration of an emergency classification. "the Duty Call Supervisor will initiate staff augmentation" using the " Emergency Recall System or Appendix A. Duty Call Supervisor Call Directory to notify I persons..." Contrary to the above. from approximately July 22 to October 3.1996. I arrangements were not available to staff or activate the TSC. OSC. or EOF ' in a timely manner because the licensee did not have the capability to implement either the primary method (using the Emergency Recal! System) or the backup method (using the Duty Call Supervisor Call Directory) for ! notifying its Jersonnel to report to the plant during off-hours to staff l and activate t1e TSC. OSC and EOF. ; 1 This is a Severity Level IV violation (Supplement VIII). l B. 10 CFR 50.54(q) requires that nuclear power plant licensees follow and maintain in effect emergency plans which meet the planning standards of 10 CFR 50.47(b) and the requirements in Appendix E to 10 CFR Part 50. REP Section 7.2.2. " Training of On-Site Emergency Response Organization Personnel". states. "The training program for members of the on-site emergency response organization will include practical drills as appropriate and participation in exercises, in which each individual demonstrates an ability to perform assigned emergency functions." The licensee's Plan further states. "For employees with specific assignments or authorities as members of emergency teams, initial training and annual retraining programs will be provided. Training must be current to be maintained on the site Emergency Team Roster " Contrary to the above. the licensee failed to provide a program which included an opportunity for each individual assigned to the on-site emergency response organization to participate in a drill or exercise. In l PREDECISIONAL ENFORCEMENT INFORMATION - NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
ENFORCEMENT ACTION 7-4- WORKSHEET I 1994, the licensee failed to pro,1de training for 17 positions l (approximately 92 individuals) identified as part of the on-site response l organization. In 1995, the licensee failed to provide training for ] 8 positions (approximately 54 individuals) identified as part of.the on
- 3 site response organization. The licensee's training program failed to '
include initial or periodic retraining on certain procedures required to j . be implemented by several identified positions. In 1995, the licensee i failed to remove from the emergency response organization 4 individuals ; i who had not com31eted retraining as required. The licensee failed to
- remove 6 indivicuals from the emergency response organization effective October 6,1996, who had not remained qualified to fill response team '
1 requirements as a result of allowing their respirator qualirications to l lapse. , i ] This is a Severity Level IV violation (Supplement VIII). 1 i I 1 i i PPIDECI'iONAL ENFORCEMENT INFORMATION NOT FOR PUBLIC RELEASE W/0 APPROVAL OF DIRECTOR, OE
l ] Florida Power & Licht Company, P O Box 128. Fort Pierce. FL 34954 0128 - December 2, 1994 FPL I l L-94-305 10 CFR 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 l Re: St. Lucie Unit 1 i l Docket No. 50-335 Reportable Event: 94-006 - Revision 1 Date of Event: November 23, 1994 Containment Integrity Outside of FSAR Assumptions Under Limited Circumstances Due to Desian Error The attached Licensee Event Report is being revised pursuant to the requirements of 10 CFR 50.73 to' provide an update on the subject event. I 1 I Very truly yours, D. A. a ger Vice esident l St. Lu e Plant i i i DAS/msd Attachment cc: Stewart D. Ebneter, Regional Administrator, USNRC Region II i Senior Resident Inspector, USNRC, St. Lucie Plant I h
.- . - . ~ - - . . - - . - .
. . . - - - - . - . . - _ . _ . - , . . . - . . . . _, . - - = . , . . ,
i , J i e NRC FORM 366 U.S. NUCLEAR REGULATORY CulG415510N APPROVED BY OMS No. 3150 0104 i
+
(5 92) EXPIRES 5/31/95
! ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH N *E (E) ARD NS REGARD!N BUR N S IMATE b 2
THE INFORMATION AND RECORDS MANAGEMENT BRANCH j (MNSB 7714), U.S. NUCLEAR REwulATORY COMMISSION. (See reverse for required numer of digits / characters for each block) N, 20555 0001 AND TO TM RM { d MANAGEMENT AND BUDGET . WASHIN FTON. DC 20503. - FACILITY NAME (1) DOCKET NUMBER (2) PAGE (3) St. Lucie Unit 1 05000335 1 OF 8 [ TITLE (4) Containment integrity outside of FSAR assumptions under limitec,
- circt mstances due to desicrn error.
! EVENT DATE (5) LER NUMBER (6) REPORT DATE (7) OTHER FACILITIES INVOLVED (8) SEQUENTIAL REVISION " i MONTH DAY YEAR YEAR NUMBER NUMBER MONTH DAY YEAR N/A 10 23 94 94 006 1 12 2 94 '" "*"" N/A ! OPERATING y TMIS REN 15 WIMED WUANT TO WE N!REMENTS OF 10 CFR h (Chen m or mm) (M) l MODE (9) 20.402(b) 20.405(c) 50.T3(a)(2)(iv) 73.71(b) } POWE" #''"'" "'"' * * *"' "*#" LEVEL (10) 100 20.405(a)(1)(ii) 50.36(c)(2) 50.73(a)(2)(vit) OTMER 20.405(a)(1)(ttt) 50.73(a)(2)( t > 50.73(a)(2)(v1it)(A) (Specify in l 20.405(a)(1)(iv) X 50.73(a)(2)( t t ) 50.73(a)(2)(vi t t )(8) *[* 20.405(a)(1)(v) 50.73(a)(2)( t t t > 50.73(a)(2)(x) NRC Form 366A) LICENSEE CONTACT FOR THIS LER (12) l NAME TELEPHONE NUMEER (inctuoe Area Code) ! Michael J. Snyder, Shift Technical Advisor (407) 465-3550 , a + C(MPLETE ONE LINE FOR EACM CCDIPONENT FAILURE DESCR18ED IN THIS REPORT (13) chose sTerms anscuerr Aw- CauBE SYSTEM CD90NI3fr MhMUF2CFJItER !
- N/A --- ---- --- ---
l a SUPPLEMENTAL REPORT EXPECTED (14) MONTH DAY YEAR j EXPECTED 4 YES SUBMISSION No DATE (15) ! (!f yes, constete EXPECTED SUOMISSION DATE). ! ABSTRACT (Limit to 1400 spaces, i.e., approximately 15 singte spaced typewritten Lines) (16) ( l On October 20,1994, Unit 1 was in tTode 1 operating at 100% steady state power.
- Differential pressure testing of a motor operated valve resulted in the lifting of l a suction supply header relief valve for the Emergency Core Cooling System (ECCS).
l On 23 October, an engineering evaluation confirmed that this relief valve could lift under certain accident conditions and result in surip inventory loss in excess ? of design basis into the Reactor Auxiliary Building. l The root cause of the deficiency was design error in the Iodine Removal System. i A cCxtman header in that system permitted cross train pressurization of an idle - Containment Spray purfp, pressurization of the ECCS suction bandar and the { potential to lift the relief valve on that header. This design deficie w / had ' existed since the Iodine Rertoval System was installed in 1978. 1 Corrective actions: 1) The relief valve path in the Iodine Removal system was isolated. 2) FPL Engineering evaluated the effects of increased pressure in the ECCS suction header with satisfactory results. 3) The two reliefs were then
- - disabled. 4) A satisfactory leak check test of the ECCS suction header system was l performed. 5) The Architect Engineer of the Iodine Removal System was informed of I the design deficiency. 6) A Unit 1 and 2 design review indicated no other similar problems in the ECCS. 7) The ccmfan header was physically separated prior to restart frcm the refueling outage.
i NRC_roRM 366 (s-92) . . _ __ _ . .
_ . . . _ . _ _ _ _ _ _ _ _ _.__ _- ~ ~ --
._ _ _ _ ____. _ _ _ _ m__m.__
F. 1
> NRC FORM 366A U.S. NUCLEAR REGULATORY CGWitSSION APPROVED BY OMS No. 3150-0104 (5 92) EXP!RES 5/31/95 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH NRC FORM 366A (5 92) THIS INFORMAT!0N COLLECTION REQUEST: 50.0 NRS.
FORWARD CopWIENTS REGARDING BURDEN ESTIMATE 70 LI M WMT M (M) THE INFORMAT!0N AND RECORDS MANAGEMENT BRANCH
"' N"l0"" jd%Ei TEXT CONTINUATION Md?$'0IY057.'0Ti REDUCT!0N PROJECT (31I00104), OFFICE OF MANAGEMENT AND BUDGET WASHINGT0ll. DC 20503.
FACILITY NAME (1) DOCKET NUMBER (2) LER NUMSER (6) PAGE (3) SEQUENTIAL REVISION ! TEAR St. Lucie Unit 1 05000335 94 --006-- 1 2 OF 8 , TEXT (If more space is requirec, use soditional copies of NRC Form 366A) (17) PESCRIPTION OF THE EVENT On 20 October, 1994, at 1700 hours Unit 1 was at 100% power steacbf state , after successful performance of a B train High Pressure operations. Safety Injection Irrmediately(EIIS:BQ) motor operated valve (V3662) differential pressure ' test as required NRC Generic Letter 89-10, utility maintenance personnel noted water pooling to a floor drain in the pipe tunnel in the Reactor Auxiliary Building
, (EIIS:NS). The source of the water was found to be from a reseated A train relief valve SR-07-1A, located en the 1A Emergency Core Cooling (ECCS) (EIIS:BP) suction '
piping. Health Physics personnel determined that the water was from the Refueling Water Tank. Later that same shift, utility licensed operators determined that the relief had l lifted during the performance of the valve differential test due to a previously , unrecognized pathway for cross train pressurization. 'Ihe aligrmnt for the test , revealed a flow path from the discharge of the 1B Containment Spray purfp(EIIS:BE) to the suction of the 1A Containment Spray purip through a ccRimen header in the Iodine Removal System (EIIS:BE) (See Figure One) . A review of plant records showed l that during this testing, the maximum pressure at the A ECCS suction piping was 85 ~ psig. 'Ihe desicjn pressure of the line is 60 psig. The relief setpoint of SR-07-1A and 1B is 60 psig. On 21 October, FPL Engineering was requested tc 4termine potential adverse effects of overpressurizing the 1A ECCS suction piping ai to review the operability concesn related to the potential to lift SR-07-1A during a postulated design basis accident. On 23 October, preliminary results from that review prortpted Operations to isolate the NaOH system from the 1B Cantainment Spray purrp and enter its 72 hour Action statement at 1255 hours. At 1915 hours, FPL Engineering cartpleted a calculation which determined that the ccRrponents whose design pressure had been e.xcciid were 1 capable of withstanding considerably higher pressures. The suction piping and certponents, therefore, did not suffer damage as a result of the event. However, it was concluded that a design is scenario existed which could result in lifting the relief valve. In the event of a (LOCA) concurrent with a Ioss Of Offsite Power (postulated IDOP) and Ioss the failure of Coolant of one Accident to start, SR-07-1A or 1B could o in the Emergency Diesel Generator (EIIS:EK) idle train, and after a Recirculation Actuation would release Signal (RA containment surip inventory in excess of the Engineered Safeguards equipment external leakage rate of 2 liters per hour. This would result in a'Ihis condition outside of the design basis of the Engineered Safeguards systems. design deficiency had existed since the NaOH system was backfit to Unit 1 in 1978. On 26 October, Unit i exited the 72 hour Iro when the partially disabled Iodine Removal system was fully restored to service. This was done after FPL Engineering had performed a Safety Evaluation which concluded the acceptability of disabling the two relief valves in the ECCS suction headers as an interim measure. After the suction header reliefs were disabled, a leak test on each ECCS header confirmed the , s.cceptability of this mode of operation until the corrmancement of the Unit 1 ! refueling outage scheduled to begin five days later. ! i NRC FORM 366A (5 92)
l !. NRC FORM 3664 U.S. NUCLEAR REGULATORY C0 polls $10N APPROVED BY OMB No. 3150 0106 j* (5 92) EMPIRES 5/31/95 I EST! MATED suRDEN PER RESPONSE TO COMPLY WITN , !- THIS INFORMATION COLLECTION RE0uEST: 50.0 HRS. N N (E) F MA A RE $ BRAN (""*8 771'), u.S. NUCLEAR REGuLATORT CuMMIS$10N, - 4 W N TM WASHINGTON, DC 20555 0001 AND TO THE PAPERWORK r ,' REDUCTION PROJECT (3180-0104), OFFICE- 0F ' i MANAGEMENT AND BUDGET. WAsMINGTOI. DC 20503. FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) PAGE (3) l SEQUENTIAL REVISION 4 . YEAL NuMsER NuMsER St. Lucie Unit 1 05000335 94 --006-- 1 3 OF 8 ; 4 i TEXT (It more space is required, use additional copies of NRC Form 366A) (17) ! l ! ! CADEE OF THE EVENT , a l The root cause of this event us a design deficiency in the Iodine Removal System. ! I The Iodine Removal system is a subsystem of the Cantainment Spray system which is i used.to remove post-accident iodine from the c<mtainment atmosphere following a ' i IDCA by adding controlled amounts of sodium hydroxide (NaOH) to the containment
; spray water. This is acc lished by maintaining the containment spray solution pH
- within specifications to a ' eve rapid absorption of the radio-iodines and to
; minimize caustic corrosion of materials and protective coatings within the ; containment. The specific design error was that the backfit of the NaOH system in l 1978 did not consider the adverse potential consequences of using a carmon return
- bandar from the discharge of the two containment Spray ptmps to the two NaOH j eductors located near the suction of each Containment Spray ptmp. The discovery of t this event occurred during the GL 89-10 differential pressure testing of the 1B
, Containment Spray ptmp cross tie connection to the 1B High Pressure Safety Injection ptmp. Other plant test and surveillance procedures had isolated the NaOH system'and therefore had not detected this design deficiency. i ANALYSIS OF EVENT: i j The postulated lifting of SR-07-1A or 1B is re rtable to the NRC under i 10CFR50.73.a.2.ii as "Any event or condition t resulted in the nuclear power l plant being in a condition that was outside the design basis of the plant." . l i I The purpose of the Containment Spray system is to prevent the containment vessel ! from exceeding its design pressure of 44 psig following a IDCA, assuming a s' le i active or passive failure. The Containment Spray system consists of two ra h nt l trains. The heat removal capacity of either train is adequate to keep containment , pressure and tenperature below design values. 'Ihe purpose of the ECCS sucticn i relief valves, SR-07-1A and 1B, is to provide relief capability between the low i l' l pressure suction piping and the higher pressure portion of the suction piping used L for shutdown cooling. I.aw Pressure Safety Injection pump (LPSI) (EIIS:BP) check i i valves and ECCS suction ha=dar relief valves were installed to protect against- ! l leakage across motor operated isolation valves or theshutdown failure tocooling. isolate this 'Ihe ECCS l i portion of the low pressure system prior to 1.nitiat l j suction header relief valves are cme and one-half ' reliefs. l ] i One design basis scenario of concern is a large break IDCA with a Ccntainment spray Attuation Signal and a ICOP coincident with one Emergency Diesel Generator failing to operate. 'Ihis would result in cross train pressurization to the non-running i a
} ECCS train, and open a suction header relief valve. After an RAS, ccntainment sunp i j- inventory release would be in excess of the Engineered Safeguards equipment i external leakage rate of 2 liters per hour assunptions (FSAR section 15.4.1) . The i maximum leakage rate from the relief would be limited by the design flow of the 1 NaOH spray additive system eductor at 128 gallons per minute.
i 1 l,- NRC FORM 366A (5 92)
,_-~-.- . . - - ~ _ - - . - - - - _ . - - . - - - . - - - -~ .-.-_-s.~ng~~~
4 i $ NRC FORM 366A U.S. NUCLEAR REGULATORY CG011SSION APPROWED RY OMR NO. 3150-0104 ; d (5 92) EXP!RES 5/31/95 ; ! ESTIMATED BURDEN PER RESPONSE To COMPLY WITH i THIS INFORMATION COLLECT!DN REQUEST: 50.0 HRS. ' 4 FORWARD CCe#IENTS REGARDING BURDEN ESTINATE 70 < 1 IJI D MU U ( ) THE = INFORMATION AND RECORDS MANAGEMENT BRANCN I NG D 2'05 000 AND TO TH n REDUCTION PROJECT (31 0 0104), OFFICE OF i { MANAGEMENT AND RtmCET, WASHINGT0th DC 20503. FACILITY NAME (1) DOCKET NUMBER (2) LER NUMBER (6) PAGE (3) SEQUENTIAL REVISION YEAR
- St. D.icie Unit 1 05000335 4 OF 8 a
94 --006-- 1-i TEXT (If more space is requiroc, use additional copies of NRC Form 366A) (17)
- AIDLLYSIS OF THE EVEtfr (contirnaad) ;
h Two additicnal scenaric,s which result in relief valve lifting were identified. One i geenario postulated a large break IDCA and one containment sump recirculation valve l l failing to automatically open after an RAS. 'Ihis would necessitate shutdown of the l { affected ECCS train to avoid cavitation of s in that train. The second j scenario stulated a small break IDCA whi does net ' actuate containment spray. A j relief ve would lift on an idle ECCS train during recirculation when a i containment spray pump is procedurally ali to a High Pressure Safety Injection
- punp for NPSH enhancement. These small large break IOCA scenarios described j above were evaluated for past significance to plant operation and safety. '
l l FPL Engineering ccxTpleted calculations to show that the containment spray system's
- ability to supply the containment with the design flow rate of at least 2700 '
i
- gallons per minute was not compromised with the diversian through the idle spray j pump's header and out an ECCS suction header relief under the design basis
{ scenarios of concern. An additional calculation determs.ned that the cCrrponents , whose design pressure had been exceeded during the MOV differential pressure i
- testing on 20 October were capable of withst considerably higher pressures j and therefore did not suffer any damage as a re t of this event.
t l A review of flooding effacts in the ECCS punp rooms was performed. For lartye break 4 IDCAs, the Reactoran RASCoolant will stop System LPSI punp(EIIS:AB),s all (RCS) which provides the suctionan ECCS reliefheader vent path oack to reseat i and terminate fl W 4 m . For small break IDCAs wi t Containment Spray actuated, l if the size and location of the RCS break allows Shutdown Cooling (SDC) (EIIS:BP) to j be placcd in service prior to RAS, the idle ECCS train would not be pressurized. ! If during a small break IDCA the SDC system could not be placed in service prior to ' RAS, than Emergency Operating Prdwe 3 (EOP-3) , Tn== of N 1=nt Acc W nt, l directs the operators to align a Containment Spray pung to a High Pressure Safety i Injection pung for NPSH purposes. This ali t would open an idle train's.ECCS j suction relief. The volume of water from relief valve could be contained for 3 j hours without disabling the equipment in the idle ECCS train, and would be
- contained for 18 hours without adversely affecting the ECCS punps and safety
! related equipment cri the operating ECCS train. 'Ihis is a reasonable time for which
- prMwal and plant staff initiated contingencies would be inplemented to diagnose
! and mitigate flWim effects in an ECCS punp room. In any IDCA scenario, j operators would be alerted to fl W ing by control room annunciation of the ECCS cunp level monitors. EOP-3 requires operators to check the status of these four
- simo monitor alarms; then to investigate and attenpt to isolate the leakage causing i high level alarms in either of the two sumps. Prior to RAS, operators may have i enough time to disable the relief by installing a gaggincy device mounted on the
! valve. After RAS, procedural guidance for remot.el
- to the Reactor Containment Building (RCB) (EIIS:NH)y pumping sunp via a dedicated downpump the ECCSsystem room I is a specific step in EOP-3. However, this system would be unavailable during a 1- IDOP. In the event that these success paths were not inplemented, the onsite j emergency response organization would have sufficient time to diagnose and, mitigate i the flooding in the ECCS punp room prior to rea the opposite ECCS train. More inportantly, since the ECCS suction relief lift is t upon a high (cJreater
- than 37 psig) RCB pressure or continued Containment Spray punp operation, it is unlikely that unmitigated flooding in an affected ECCS punp room would continue for, a w e than 3 hours.
5 NRC FORM 366A (5 92)
4
- NRC FORM 366A U.S. NUCLEAR REGULATORT COB 9815$10N APPROVED FY OMS No. 3150-0104
, (5 92) EXPIRES 5/31/95 EST! MATED BURDEN PER RESPONSE TO COMPLY W!' N THIS INFORMATION COLLECTION REQUEST: 50.0 HR!i.
mm WBC MRT (M) FORWARD COMMENTS REGARDING BURDEN ESTIMATE f0 THE INFORMATIOu ANO RECORDS MANAGEMENT BRAktN
- TM '
M NG N o N'as N00$ "A E T0 THE E E 1 t REDUCTION PROJECT (31!IO 0104), OFFICE OF MANAGEMENT AND BUDGET. WASHINGTOsh DC 20503. ' FACILITY NAME (1) DOCKET Nt.SIBER (2) LER NUMBER (6) PAGE (3) YEAR SEQUENTIAL REVISION
***'" "**E" St. Lucie Unit 1 5 OF 8 05000335 94 _ 006-- 1 l
TEXT (if more space ti; required, use additional coptes of NRC Form 366A) (IT) l ANALYSIS OF TW EVI!Nr (r emt hath ; ) i This review also concluded that the unaffected train's safety related equipment i located throughout the Reactor Auxiliary Building would operate within the bounds of ' their environmental qualifications in the event of an ECCS suction relief lift. Leakage from ECCS components during a IfCA and recirculation phase provide a source l of fission product leakage external to the containment. All ECCS cortponents l containing recirculating sump water are within the controlled ventilation area cerved by the ECCS area ventilatican system. This safety related system processes le.akage from ECCS components through a charcoal filter before release to the i Etmosphere via the plant vent. Relief valves SR-07-1A and 1B both relieve in l compartments which are served by the ECCS ventilation system. FSAR section 15.4.1.7 describes the assumptions for determining the offsite dose cotiponent from ECCS leakage. The offsite and onsite dose consequences of the relief valve's . leakage rate were analyzed using the source term factoring described in NUREG 1465 ! and by increasing the particulate filtration efficiency to operational values. 1 Results frcm that analysis showed that the offsite dose consequences from the three postulated scenarios would not exceed 10 CFR Part 100 Guidelines, and that the ansite dose consequences would not exceed 10 CFR Part 50 General Design Criteria. Therefore, the health and safety of the public were not affected by this condition. CORRECI'IVE ACTIONS:
- 1) As an interim measure, Operations isolated one train of the Iodine Retroval system to preclude cross connecting the ECCS headers and lifting the suction reliefs.
- 2) FPL Engineering evaluated the effects of exceeding the design pressure of the ECCS suction header during this event and found that the cotiponents were capable of withstanding considerably higher pressures and had not been overpressurized or suffered damage.
- 3) FPL Engineering performed a Safety Evaluation which determined that the ECCS suction headers could withstand pressurization up to the Cantainment Spray pump discharge head ccncurrent with the disabling of the relief valves.
- 4) As an interim measure, the two ECCS suction header relief valves were disabled.
- 5) The Technical Staff performed satisfactory leak testing of the ECCS suction
, header.
- 6) Operations fully restored the Iodine Removal system to service within the 72 hour LCO time limit.
- 7) A review of the Unit 2 Iodine Removal system verified that it was not susceptible to a similar design deficiency as noted on Unit 1.
NRC FORM 366A (5-92)
..__m . . . . - - . . . - .m. _ _ _ . _. ___ _ . . . _ . . _ _ _ _ . -. . . - - - _ _ . _ _ . . _ . . _ . _ _ _ _ . -
I 4 NRC FORM 366A U.S. NUCLEAR REEILATORY C019418510N APPROVED SY (me Lo. 3v50 0104
, i (5 92) EXP!RES 5/31/95 l* ESTIMATED BURDEN PER RESPONSE 70 COMPLY WITH l THis INFORMATION COLLECTION REQUEST: 50.0 NRS.
- MM M M (E) FORWARD C0188ENTS REGARDING BURDEN ESTIMATE To THE INFORMATION AND RECORDS MANAGEMENT BRANCH g g'{'g l (NISB 7714), U.S. NUCLEAR REGULATORY C01891SSION, WASHINGTON, DC 20555 0001 AND TO THE PAPERWORK RE00CTION PROJECT (31$00104), CFFICE OF MANAGEMENT AND BUDGET, WASHINGTOII. DC 20503.
I FACILITY NAatE (11 DOCKET NLAIBER (2) LER NUMBER (6) PAGE (3) TEAR S20UENTIAL REVISION St. Lucie Unit 1 "E """ 05000335 6 OF 8 l 94 --006-- 1 l TEXT (if more space is required, use acetttonal copies of NRC Form 366A) (17) CIEt1MCTIVE ACTIONS (contiznzad)
- 8) A design review was conducted on the Unit 1 and Unit 2 ECCS piping used during 3
injection and recirculation redes of operation. No other paths for cross flow were
; identified to be outside the license design basis.
i 9) A permanent modification to physically separate the cocmon NaOH eductor was accomplished prior to unit restart from the refueling outage. (See Figure Two)
- 10) FPL En i deficiency.gineering has informed the plant Architect Engineer of the this design
- 11) Lessons learned from this event were shared on the INPO's Nuclear Network.
I j AnoITraNAL INFOBETIC27 4 sv_ stem Telanci fication: l Iodine Removal System: NaOH System with eductors Architect Engineer: Raytheon (FhamCO) NSSS: Combustion Engineering l Previnus Simi1 at- Brenen : A previous LER at St. Lucie related to design deficiencies which resulted in a condition of the plant being outside of the, design assumptions in the FSAR is LER 335-80-27, "T1nana1yzed Baron Dilution Transient." NRC FURM 366A (5-92)
_ _ . . . _ . _ _ _ . ~ . . . . . _ . _ _ . _ . - . _ . . . . . _ _ _ _ _ . . _ . _ _ . . _ . - . . _ . _ _ . - 4 1 , , NgG FORM 3664 u.S. NUCLEM REQULATORUCGellS$10N I APPROVED 87 oms No. 3150-0104
! )
(5 92) EXPIRES 5/31/95 i , EST! MATED BURDEW PER RESPONSE TO COMPLY WITN i THIS INFORMAfl0N COLLECTION REQUEST: 50.0 MRS. j FORWARD CapetENTS REGARDING BURDEN EST! MATE TO 4 LI M N N (EI THE INFORMATION AND RECORDS MANAGEMENT BRANCN j
- g g gg (pulBS 7714), U.S. NUCLEAR REEALATORY CWWIIS$10N, WASHINGTON, DC 20555 0001 AND TO THE PAPERWORK
- REDUCTION PROJECT (31 0 0104), OFFICE OF '
j MANAGEMENT AND BtmGET. WASNINGToll. DC 20503. i FACILITY NAftE (1) DOCKET NtalBEl- (2) LER IRAISER (6) PAGE (3) fj SEQUENTIAL REVISION' TEAR
- NunsER NunsER St. Lucie Unit 1 7 OF 8
; 05000335 94 --006-- 1 i
i TEXT (If more space is requiree, use emettionet copies of NRC form 366A) (17) i j I f Qe numsimo y j 7"" O sitpadE TANK -- I $ os aA 2m uo73A Lo
- ,.0,.,,
- ,- er-i A m L I
k
- Lo a
- - to $
uor se *% f to m2 u2 i r , r , A. soucron , f e m
,- M.% A ta Y
_ a h
- s _.m -
! mer.1e mer.ta f, L 4 M . so N - 1 A '8' WETY t =,s.,, i ,
~anaestie sensmusam
"*'8'a'n"' on .i 4
'un.as.
0888' "n,,s,a,"a, n"'"M
- y g v. seat g to muevaa y pcW471e ). !
Q % - - ewer.se h - i . mumuCD4 an,rassemf "incemto" - - - = - - -
- spaAY mass cowtassent meer j swer4A T i T i 2
) '
N d swer4e .. i $ 8 ! RGURE M - CONTAINMENT SPRAY SYSTEM (ONGINAL NaOH ADDm0N DESIGN) 1 i j NRC FORM 3664 (5 92)
J . 1 ! U.S. NUCLEAR REGut,ATORT CCR0llS$10N i APPROWED ST ONS No. 3150 0104 NRC FORM 366A
, g$.92) EXPIRES 5/31/M
{ ESTIMATED BURDEN PER RESPONSE TO COMPLY WITh ' THIS INFORMATION COLLECTION REGUEST: 50.0 HRS. FORWARD CapetENTS REGARDING BURDEN ESTIMATE To f
- I,47. M N M (E) THE INFORMATION AND RECORDS MANAGEMENT BRANCN l
i g g-gy (MMS 8 7714), U.S. NUCLEAR REGULATORT C0100lS$10N, WASHINGTON, DC 20555 0001 AND TO THE PAPERWORK REDUCTION PROJECT (31I00104), OFFICE OF
- MANAGEMENT AND BLEGET, WA2MINGT00. DC 20503.
" DOCKET NLsesER (2) LER NUMBER (6) PAGE (3)
FACILITY MAME (1) SECUENTIAL REVISION TEAR NLDIBER NLS4BER St. Lub:le Unit 1 8 OF 8 05000335 94 --006-- 1 4 f TEXT (It more space is required, use enditionet copies of NRC Form 366A) (17) i I an.na.t.mo _ TAsEE montess ,h STtmAm TAsut *j 074A LO 888AY St OF A t~ 071g 071 A % to y g MEAgum
& asGML88
. r m LO fd
/1' b
g $ McF te $d M h 7I ?I I Z,Zl - d) 8"' i g PCV of-1 A o+ ,,
,= ._
g,gg = IW=OF SA
$64715 547 I A ,, ..
p h -
' '> v v4888 iAppgapgTy k useDE N
iP M m A WES = MSM em noche ~ 4 WAR E% 0 te SAftTY acone pwgg 1r '4 % ,o gygggg - tRASI f,fg S O'[ M % mar guCTENI Mm muC= w_ 'M v sess m pCv4F-18 D4 a rA
,q r
i,TC,6'- M '" * " ""
,( __ro-
= aa' anrA r 889
'4'==
/ t#474A 38 f R=S2
,~ade w
FIGURE TWO - CONTAINMENT SPRAY SYSTEM (MODIFIED NaOH ADDITION DESIGN) NRC FORM 366A (5 92) i
- E g v-cat 6 m h.4T % a c -L_
e m j i gm{r6 Tc: PT. 'N1, h T" ,(o 1 % o M N M W Cte* C' - . , JCALATED ENFORCEMENT PANEL QUESTIONNAIRE l INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMENT PRE-PANEL 2 i PREPARED BY: R. L. Prevatte
; NOTE: The Section Chief is responsible for preparation of this questionnaire '
! - and-its distribution to attendees prior to an Enforcement Panel. (This-3 information will be used by EICS to prepare the enforcement letter and Notice, i i - as well as the transmittal memo to the Office of Enforcement explaining and
- justifying the Region's proposed escalated enforcement action.)
l 1. Facility: St. Lucie !~ 1 Unit (s): 1 ) ! l'
- Docket Nos
- 50-355 License Nos: DPR-67 e Inspection Dates: Auaust 28 - September 30. 1994 1
- Lead Inspector: R. L. Prevatte
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate") which includes the l , recommended severity level for the violation is enclosed, e j [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of I specificity as to how and when the requirement was violated. [X} Copies of applicable Technical Specifications or license 3
- - conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best ;
i fits the violation (s) (e.g., Supplement I.C.2) ; e j VII.D.2 ' i i l 3 ! 4
-THIS DOCUMENT COWTAINS PREDEC!sIONAL INFORMATION -
IT CAN WOT BE Di',CU,$ED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 5 h 4 i
l 0 l l . [ ESCALATED ENFORCEMEliT PANEL OUESTIONNAIRE [ :4. What is the apparent root cause of the violation or problem? l The aooarent root cause(s) for the event are: o e- 8_dgsire on the cart of the ANPS'to chronolocically tie 1A EDG inoperability to the chance in swina bus power supply lineuo made l earlier in the day. This was a conservative decision with respect i to the time allotteu in the' applicable TS AS. i e A desire by the licensee to take credit for hourly RCO control board walkdowns as satisfyina AS (b) of TS 3.8.1.1 and to l represent such actions:as havina occurred within the TS time 4- reautrements. j e An accarent'i..;: communication between the ANPS and the Operations i' i Supervisor as to how the subject loa entries should be made. ' i The miscommunication was most orobably perceptual on the part of I- the ANPS. The ANPS in auestion has had disaareements in the past j with the Operations Suoervisor, orior to his annointment as Operations Supervisor. The inspector witnessed one such l disaareement (one cited by the_ ANP5 in his discussion of this event as drivina his actions) durina a Unit 1 startuo. in which ! the ANPS refused to sian off a procedural step without first obtainina a TemDorary Chanae to correct a misleadina reauirement. The Operations Supervisor (then Assistant Operations Suoervisor) i insisted that the ANPS sian off the sten, annotatina it with an ' explanation of what portions of the step did not apply to the ; sianoff. This methodoloav of dealina with crocedural problems was i not an acceptable method per clant procedures and recent manaaement direction and the ANPS held fast to his position. The I disaareement arew more intense and the (then) Operations . l Supervisor and Operations Manaaer were summoned to the control room to resolve the issue. After a short review. the (then) Operations Suoervisor directed that the procedure in ouestion be revised via Temoorary Chanae. in accordance with clant orocedures. The inspector felt at the time that the ANPS had performed well in maintainino his position and that the (then) Operations Supervisor had made the correct decision with reaard to the actions reauired to correct the situation. In the current event, the ANPS explained to the insoector that he perceived the (now current) Operations Supervisor as directina him
~to modify the subject loos. althouah he acknowledoed that no direct statement to that effect was made. Given his cerception.
1he ANPS stated that he was unwillina to ao throuah another. araument with the (current) Operations Supervisor, fearina that it would, ultimately, affect his job security. THIS DOCUMENT CONTAINS PREDEcl$10NAL INFORMATION - IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 6
k* i-r
=
b, l ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE l l 5. State the message that should be given to the licensee (and industry) :
- through this_ enforcement action.
b - Control room loas must provide a chronoloaically accurate descriot'i on of ; a the actions performed on a aiven shift and must remain inviolate. I 6. Factual information related to the f'ollowing civil penalty escalation or , i mitigation factors (see attached matrix and ! l 10 CFR Part 2, Appendix C, Section VI.B.2.): : 1
- a. i IDENTIFICATION: (Who identified the violation? What were the '
F - facts and circumstances related to the discovery of the violation?
- Was it self-disclosing? Was it identified as a result of a i
- generic notification?)
! The violation was identified by the resident inspector reviewina I the licensee's loas followina an EDG operability issue. t I b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, , ! describe preliminary information obtained during the inspection j and exit interview. 8 j The licensee has counseled the individual responsible for the i , modification of the subiect loa entries. The Operations
')
Department issued a Nicht Order reinforcinq existina procedure l auidance reaardina lookeepina. After beina told, on September 1. l ' that the inspector found the loas unsatisfactory (they had not ' been corrected to indicate that the Avaust 29 entry was l misleadina). the licensee made a late loa entry correctina the historical record. l What were the immediate corrective actions taken upon discovery of [ the. violation, the development and implementation of long-term [ . corrective action and the timeliness of corrective actions? ' c ! See above.
- What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis?
l The licensee has concurred that the modification was not in i accordance with site policy. The issue is still emeraina at this i time and has not been fully developed by the licensee. i $ l
- )
i 4 { --THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION-- 1 IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE i l APPROVAL OF THE REGIONAL ADMINISTRATOR 7 j [ l 4 : I
, , w--,.,e
ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): No recent cases of modification of records have been identified. Identify the applicable SALP category, the rating for this category and the overall rating for the last two SALP periods, as well as any trend indic'ated: SAlfu'atecory: Operations The licensee has achieved SALP ratinas of I for the last two SALP periods. There have been an increasina number of events associated with Operations in the past six months: however, these events have not resulted in the identification of a clear trend,
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunitier for the licensee to discover the violation sooner such as throuph normal surveillances, audits, QA activities, specific NRC or ir4dustry notification, or reports by employees?
Licensee manaaement could have, in the course of loa reviews, identified the violation: however, knowledae of the timina and oroaression of the 1A EDG operability issue would have been a DrereQuisite to such an identification.
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this inspection? If there were, identify the number of examples and briefly describe each one.
There were not multiole examples of this violation identified durina this inspection period.
- f. DURATION: How long did the violation exist?
This violation occurred in an isolated fashion. The chances tq the control room loa were identified approximately 2 days after the occurrence. ADDITIONAL COMMENTS / NOTES:
-THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 8
ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE ,
-NOTICE OF VIOLATION Unit 1 TS 6.8.1.a required that written procedures shall be established l and implemented covering the activities recommended in Appendix A of .!
Regulatory Guide 1.33, Revision 2, February 1978. Appendix A, paragraph 1.h includes administrative procedures for. log keeping. St. Lucie - Administrative Procedure 0010120, revision 63, " Conduct of Operations," Appendix F, " Log Keeping," stated that log' entries were to be made in a-- l chronological order and that, where this was not possible, entries were . to be preceded by the words " Late Entry." : Contrary to the above, on August 29, 1994, a Unit 1 Assistant Nuclear Plant Supervisor modified and appended Unit I control room log entries made on a previous shift. The modifications were not annotated in any way and' created a false impression of the activities of the previous shift.. l i l l 1 l i
--/HIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
IT CAN NCT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 9
b .. ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE I i ! During a Unit I control' room tour. conducted at approximately 4:00 p.m. August ! 29, the inspector noted that the 1AR 4.16 KV bus was aligned to the IA3 4.16 , 4 KV bus and that the IC ICW pump was operating in lieu of the 1A ICW pump.- The '
- lineup had been made to support maintenance activities in the Unit 1 intake i ' bays. The 2AB bus was normally aligned to the 183 bus and was the source of l power for the IC ICW pump. ~During a postulated LOOP, the 1A3 bus would be a
powered by the 1A EDG. The electrical lineup in question was effected at 1:26 2 p.m. on August 29. s As documented in IR 94-12, the IC ICW pump had never been tested for load ' shedding capabilities when powered with the 1AB bus aligned to the 1A3 bus.
- .As a result, TS surveillance 4.8.1.1.2.e.3.a and 4.8.1.1.2.e.5.a, which verified load shedding capabilities in response to LOOP and LOOP /SIAS signals, I i had never been satisfied. As these surveillance tests formed part of the '
j -bases for 1A EDG operability, the operability requirement of TS LCO 3.8.1.1 l l was not satisfied when the IAB bus was aligned to the 1A3 bus with the IC ICW ; i pump operating. During a postulated DBA involving a loss of offsite power, ' l the ICW pumps were designed to load shed from their respective busses and sequence back onto the busses in 9 seconds. The design feature was provided . i to prevent EDG overload conditions during reenergization of IE busses. A ! failure of an ICW pump to load shed would have the effect of moving the pump from the 9 second to the O second EDG 1ead block, increasing the EDGs starting load. The inspector questioned the ANPS as to the operability of the 1A EDG, given that the 1AB bus was aligned to the IA3 bus. The ANPS stated that he was aware that the electrical lineup in question resulted in IC ICW pump inoperability and that the pump had been declared inoperable accordingly. The ANPS stated that the basis for his determination was a Night Order which stated that the pumps powered from the 1AB bus could not be taken credit for. when aligned to the 1A3 bus. A caution tag had been hung on a IA3-to-1AB breaker handswitch to that affect. The inspector raised his concern regarding EDG operability to Operations Department management. After discussions with ! engineering and other plant personnel, Operations management directed that the 1A EDG be declared inoperable based upon the noted failure to perform required i surveillance testing. The 1A EDG was declared inoperable at approximately 5:00 p.m., however the licensee chose to establish the time of inoperability i at 1:26 p.m., the time the noted electrical lineup was established. In response to this issue, the licensee performed an evaluation of 1A EDG performance for the subject electrical lineup. As the load shedding capabilities of the IC ICW pump had never been tested, the analysis assumed that the pump would not load shed, effectively moving the pump to the 0 second load block of the 1A EDG. The licensee found that the combination of the 1A HPSI pump (400 HP) and the IC ICW pump (600 HP) alone was enough to exceed the < motor starting capability of the EDG, described by Figure 3 of the EDG system DBD as approximately 980 HP.
-THIS DOCUMENT CONTAINS PREDECISIONAL INFORMAfl0N -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 10
i ! l j ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE j i . The inspector concluded that, in a Night Order dated May 3,1994, the licensee failed to accurately convey to operators the findings of IR 94-12, Paragraph l 4.d, which stated, in part: i , "On Unit 1, the swing pumps have been normally aligned to the B-train l , safety bus...The inspector...found that the same failure to adequately
- test load shed capability' existed; however, the failure involved not i
- testing the IC ICW and CCW pumps when powered from the Unit 1 A-train i 5
safety bus. l i [The failure to properly t'est the load shedding characteristics of the j i Unit 2 swing pumps]...resulted in the 2B EDG not being demonstrated . I operable for the periods in which the C ICW pump was aligned to the B- ) j train safety bus..."
]
In response to this issue, the licensee generated a new Night Order which i correctly described the impact of aligning operating 1AB bus pumps to the 1A3 j
- bus. The failure to adequately convey operational limitations to control room '
! operators resulted in a recurrence of operating a Unit's electrical plant in a i configuration for which EDG operability had not been demonstrated. The ! licensee's failure to prevent this recurrence is a violation (335/94-20-01). i
- At approximately 11
- 00 a.m. on August 31, the inspector reviewed the Unit 1 )
control room log and found the following: ; ! e An entry, made at 1:26_p.m. on August 29, described the change in I i the slectric plant described above. At the end of the ! I description, the entry stated ".. 1A EDG 00S." { e An entry, timed at 2:26 p.m. on August 29, stated "1C Pump
- operable, offsite power available, redundant 'B' components i operable. "
- As the 1A EDG was declared inoperable at approximately 5:00 p.m. as a result
~
of the inspectors observations, the inspector questioned control room i operators about the log entries (the operators questioned had been on watch when the electrical lineup was changed on August 29).
- The operators had no knowledge of the log entries detailed above. The inspectors discussed the issue with the Operations Supervisor, who stated that the entries were most probably made by the peak shift ANPS on August 29 to reflect the fact that the EDG was declared inoperable. The Operations Supervisor also stated:
'p o The time of EDG inoperability had been declared to be the time when the 1AB bus was aligned to the 1A3 bus (1:26 p.m. on August. 29). e The entry describing the availability of offsicr, power supplies I and the operability the IC AFW pump and B siJe ECCS components had
--THIS DOCUMENT CONTAINS PREDECISIONAL INFORMt.TI(N** l IT CAN WOT BE DISCLOSED OUTSIDE NRC WITHOUT TH! j APPROVAL OF THE REGIONAL ADMINISTRATOR 11 l
)
m _ . . - _ _
. . ~ . - - . - . - - - - . - . -.--.-.----- . . . _ . . _ . -
t, I ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE $ been made to satisf'y AS (b) of TS LCO 3.8.1.1, which required such checks when an EDG was declared inoperable. The entry was said to I take credit for normal control room walkdowns and log entries in 3 the RCO, control room and out-of-service logs. e - The method of log entries in this case was not .in accordance with i site procedures. } The inspector. discussed.the matter with.the ANi>S who had been on ' duty during' l the peak shift'on-August 29. The ANPS stated that he did make the log entries in question and that the entries were the result of a discussion with the j Operations Supervisor, who had directed the ANPS to make log entries describing inoperability of the 1A EDG. The ANPS stated that.his l understanding of the Operations Supervisor's directions was that the logs from the day shift of August 29 should be augmented to include the EDG inoperability. . The ANPS stated that, in the course of the discussion, he 1 informed the Operations Supervisor that, if inoperability was taken from 1:26 i . p.m., then the one hour period for completion of A5 @) of TS LCO 3.8.1.1 had-been exceeded. The ANPS stated that the Operations Supervisor directed that
- . RCO board walkdowns and various control room logs be taken credit for as
- satisfying the AS, a practice which had been used in the past under similar
- . circumstances. Finally, the ANPS stated that he had made the noted log i entries with hesitation, but believing that the actions were made under the '
direction of the Operations Supervisor. F j i The Operations Supervisor acknowledged the discussion, stating that he had ! directed the ANPS to declare the 1A EDG inoperable effective at 1:26 p.m. on .[ August 29. The Operations Supervisor stated that it was not his intent that l the previous shift's logs be altered and that an apparent miscommunication had ! existed between himself and the ANPS. 1 i The inspector reviewed the Bases for TS LCO 3.8.1.1 which, with regard to the verification of offsite power and component operability required in AS (b) of
- the LCO, stated:
"The term verify as used in this context means to administrative 1y check
! by examining logs or other information to determine if certain components are out-of-service for maintenance or other reasons. It does not mean to perform the surveillance requirements needed to demonstrate ( .the OPERABILITY of.the component." '- Consequently, the inspector found that the methodology employed for making the
- 2
- 26 p.m. log entry of August 29 was in keeping with the TS. However, the inspector found that the time logged for the activity was misleading both in t the statement of when the activity occurred and by whom the activity was.
; performed. ,
I
? .
I j - THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION-- 4 IT CAN NOT BE DISCLOSED QUTSIDE NRC WITHOUT.THE 8
- j. APPit0 VAL OF THE REGIONAL ADMINISTRATOR 12 i
-l j
i ES.CALATED ENFORCEMENT PANEL OUESTIONNAIRE i Therefore, the inspector concluded that :
- e The portion of the August 291
- 26 p.m. log entry stating that the ;
- lA EDG was 00S, was misleading i-n that the EDG was declared 00S at )
- approximately 5:00 p.m. that day. Further, the entry did not
- reflect the activities of the day shift operators.
1- e The August 29 log entry of 2,26 p.m., stating that offsite power y sources were available and that the IC AFW pump and redundant B
- side components were opere'le, o was misleading in that the subject verifications were not performed on that shift.
In response to this event, the licensee issued a Night Order on August 31 p reiterating procedural requirements for maintaining logs chronologically. ~ . The inspector reviewed Administrative Procedure 0010120, Revision 63, " Conduct
- of Operations," and found that Appendix F covered log keeping. Section 2 of the appendix stated, in part, "... entries are to be made in chronological
. order. Where this is NOT possible, entries shall be preceded by the words Late Entry." The ANPS's actions, relative to the modification of the logs of i the previous shift were counter to the requirements in the procedure and, as such, constitute a violation (VIO 335/94-20-02).
-THl$ DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 13 l
..-__.-..__. - ..._ __ __._._-_~__ -~~__ ._.-~_____ _..~_--_
l a i 1 ! . 4 i . ESCALATION AND MITIGATION FACTORS (57 FR 5791, February 18, 1992) ]- j . IDENTIFICATION CERRECTIVE LICENWE PRIER Igm.TIPLE DLRATItul nrnassursS l ACTION PERFONIAIICE OPPORTlallTY TO ' IDEllTIFY
+/- 50% +/- 50% +/ 100% + 100% + 100% + 100%
Licensee Timeliness of current Licensee should Multiple Used for
- identified (M) corrective violation is an have identified examples of significant ITo be applied action (M) isolated violation violation regulatory even if IDid NRC have failure that is sooner as a identified message tb '
i licensee could to intervene to inconsistent result of prior during Licensee. (E) i have accomplish with licensee 8s opportunities inspection , identified the satisfactory good such as audits (only for SL I, i violation short term or performance (M) (E) II or I!! ! sooner) remedial action violations) (E) l (E)) ! NRC identified Promptly Violation is opportunities OTHER CONSIDERATIONS reflective of avellable to 3 (E) developed schedule for licensee's poor discover 1. Legal! aspects'and potential 1 j tone term or declining violation such . litigation risks < J , i corrective performance (E) as through actton (M) prior 2.' Negligence,' careless dia - notification regard, witifulness and-f (E) management involvement 1
~
l Self- Degree of Prior Esse of earlier 3. - Econoonc, personal orc disclosing licensee performance and discovery (E) . 'corporste gain (M 25% If initiative (M) effectiveness there was [To develop of previous 4.1Any other-regulatory frame + initiative to cotrective corrective . work factors that need to be-identify root actions and action for considered pending actiong . cause) root cause) similar with regard to licensing,. violations canaission meeting,?or. press.
- conference.
Licensee Adequacy of the SALP - Period of time identified as root cause Consider: between 1.Enihettis the intended message a result.of analysis for SALP 1 - (M) violation and :for the licensee and ther generic the violation SALP 2 - (0) notification . Industry?; notification (M) SALP 3 - (E) received by (M) Licensee (E) L...........N0TES -- k a a.- ' Comprehensive Prior Similarity corrective enforcement between the action to history vlotation and prevent including notification occurrence of escalated and (E) similar non escalated vlotetton (M) enforcement s inmediate Level of corrective management action not review the takets to notification restore safety received (E) and compliance (E) SAFETY $1GNIFICANCE: In determining the safety significance of a violation in conJmetion with the enforcement process, the evaluation should consider the technical safety significance of the violation as well as the regulatory significance. Consideration should be given to the matter as a whole in light of the circumstances surrounding the violation. There may be cases in wnich the technical safety significance of the matter is low while the process control f ailure(s) may be significant, and, therefore, the severity level determination should be based more on the process control failure (s) than on the technical safety issue. The following factors should also be considered: 1) Did the vlotation actually or potentially inpact p @lic health and safety? 2) What was the root cause of the vlotation?
- 3) Is the violation an isolated incident or is it indicative of a programmatic breakdown? 4) Was management aware of or involved in the violation? 5) Did the violation involve willfulness?
l 006640
.. .. . . __ _ hAv_ e M *" - W -O
- I M Ni __.
.._...S.'!! '._A?(d//)m . C&c.WLMoI'ha' .N. uc. em ~7
._ - . g s 1. y H . ..y,, Q5 l 2140- Mcw.ed... o d av 'G8Po pwc. -. - . . > . , .
-- . pos./p[. men
.H-<. .nt 3 & r*q Grct fL_.. SkVZtm.". ..fz 4.4 E ."V" wm T3 re'.t.xe.wan '-
.. U Y/7.'_:r;_c yg.a_jf.,yfj_;7f}.fd(e ) inll61 3,5 c e.- . L.m . _ . . m.mX 3 g,a fc,,. ,
- _. . .. e yT.tt sfw - - - - - - - - -
__._.0 9(f- o & A[g 769 m //kA..y. job n:s ure._iu ./m9' /cj&{_my ..A,7 ogi.n <d rai f% .y0% en f.else, s 7a .swk' ' ' OG.06 - Ch.,., hs.m I.AL.. sit Caf ED73 vs I I 3 L S Y T. 4 = l'? ? 7 d'u'- G~d, ed A,w+ 6 4 # M.mt & IA.2,!!R7 srG. ...eed hfm f- W . S. E O_u...l ?_L..MDGDomM / S..DE."' / X 1%i[F~<__.. 0100 -tsoo' ._ _ (A i - =er,...,g,, ,.Muwe &
- . .85,.2ci .. c19e %NDAY .. - .
n9. ceaanoue, r ,e. . . .m.. . en, i i
%D .,e 5% ,,,,x .en is
. -. - - - - . . _ pfg gg 4 __ _ .. . l i
~
~ ~ l l l03 6 ~J % 772 a & ne D w # _. l
.i040 swmn tocupom o mecta eyoocu < a=s '
tm W i (0.50 SDtTED DIWutoce2..., e#v Ps Ar 5ot* . .
. _ .._5/( J17;';&w l DJ. Cw .
a .$5 . f01D':n W 0CP h RS'AY 3* D*tA Asw E Auf 6; l5.%'- S A M u tci f%-12 .n 9'tr,. o_ v ss IdPt./C* * (M ~ 'N4" /Lt.
- l - * !*'~ 1 ) de a L. *W .
i W S r w Q . J Q sk w ~.' < Mo .,
, tic,.a A W ~ 'a m A m. n.WO o dA t .P' 90EC* AhnF#t 4'
. ..I 3 $b ~ $ bJ5'J Ytb o - ~~ re St> C _' % P G - /fA Cth.o--
l '.._." JWUQ 'fW s 9t_%pWt._4 . o ffs er{,. reust AvAusas, x _ ggov,,sa M .T. .'4' cw t%.
; _,. .h - S C,. % _ pq P
/e e
~ ORGAA6LN. -
~ MN NUC. Per ,' ' _ M PWP-
% [.2'l / % . ChunA.._/~.fordt.5..
=. . _
1 ,,. I 2 '2 noe
. _ . . e,a._ :
_ . . . . . _ _ _ . _ . j .. - g ,,,,x,,,,, 3 CALCULAT,D S,0 MArtGIN 7 _*e y _ ... .. i 15.is>.. . secur.0__J.A1 cwe 4 iou M y... M. ..' _ . . _ . . . d$ - A m eo a ec w w_ . .'t ' ._.h o tt. 17A.a_._4.ipo atte r..is .an._b A
.. f.74 () & Y .Y9ww. f 0 _#ewd4 W4 r _ $V Yo N6
% 16 I es.r s* _ , jotrassg.m - "f
/ 75T ,.. ed.L e # ad (.. .,,,,A, [. . A 7" ,,,,,,,W_ art f $ #L f a f" _ , ,
. . .).[(Jo % 4w/ fJu!) felwr .df'N U W M r- W / ~ R_ 9 3_ .. . . .
__ i n i_. .t o.a. e ~ ~ 4 s s,..r tw c o ~.ene e-Ju n,~ c. ~ ., s o.-
. ..aac asa.... ten u - u._w.m. y .. . ..
W s.rurp_ms x.L* u . - . . . . . . . l . . . . _ . .
.. _4 ..I..N.I.... .
~
, Pe:ga 44 cf 153
}..' l ST. LUCIE PLANT
- ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 63 f -
I CONDUCT OF OPERATIONS 1 ; ) ! APPENDIX F
'j LOG KEEPING (Page 1 of 4) i
- 1. Qg[33rg[:
l A. Chronological watch station log entries shall be made in black ink or other
- permanent recording method. Log sheet and check sheet entries shall be
! made in blinck ink. ) B. There shall be no erasures, liquid paper, correction tape, highliters or other i methods of obliteration. Errors shall be lined through to indicate a deletion, i but the deletion entry shall be leglble. ! l i C. The operator making the deletion shall initial along side it and enter the correct i information. Log entries shall be concise and definithre. i ! 2. Chronoloalcal Loos: A. Log books shall be maintained at the RCO, NO/SNPO, NTO/NPO and ANPO normal stations. Entries are to be in black ink and concise and complete ! onough to{ reconstruct the events of the shift. Particular attention should be i made to the entries pertaining to any abnormal condition that occurs. The ! entries are to be made in chronological order. Where this is NOT possible, i entries shall be preceded by the words Late Entry. The following entries are
- recommer ded
I 1. Entries in the RCO log should include, but are NOT to be limited to, the i following:
- a. Conditions at the beginning of each watch,
- b. Significant changes in plant conditions.
! c. Any new condition that would limit unit generation.
- d. ial tests, as well as principle periodic and surveillance tests.
i e. Control problems associated with major equtpment or systems. i f. Peactor trips and reason, when known. t j g. Automatic protective action (e.g., SIAS, CIS, MSIS).
- I
!- i
. . - - .- -- --: -- -: - .. ._ . O
1 t~ ! UNIT 1 MAIN POWER DISTRIBUTION SYSTEM i' l i 1
,,,,,, MIDWAY 3 MIDWAY 2 MIDWAV 1
.=.. t + 4 WesYsaoxy Bus a (I == CI_ _ (I ==
ewet C met was ( seas ow#
' $(I.
( seas sees s_ ( _ _ CI ** een - I .ees l (4__ (4 ( _ _ ( me ( seae _ (,,,, wei C "" == ( eens ,,, ( ,,, C "" ! g' == C, " , m' == BAY 4 I SAYa l BAY s SAY1
- a. 1
, _ ,,. . . . === --
=44,a,',;; -
4 IPW.I. W1.ft 8 i A"". ','ll"A "T" 'T' O ,,e , w m .. .-, A I.WR, w .v =
.e IEa av wo e,J, -[]
gygg, e%r% 7%e9 #y4 gpgg,
- - -O g U-
-Q ~
.r O u rri I m == -
l u. u .. Q6 p"5.'- I5 *= = s ' b= y
-a a ~~-6
~
6: a-=a - 6%a,,-.C)@ "' u D-
=.~ a - -Q D-
~ a. .e --.- ,e e 4
=_g 1 := x x .'.7, = = ~
* = 1 ...- -
L _t._- =T_w
-a x: :: a - h_
=. ::.
c - - obb -
- - -= -6 -
L g- l .= omo l l l l _g
'. .- = a6 -
o a:-
._o L- =.
.o o -.-
~ ,=
. = . _.a
== m
== 0 o
a r n.".="
-- =o .a -
r3 -.
.=_.
~
- ._ g
...".:=.r,, '.,-".0 _
0- _
.a- -" " -
" . ' * . "-O D
.u -
(rescoctresawrse) - :
.. u.
c 0711502, Piev. 7. Figwe 1 M FOR TMAINING USE ONLY t
. - _ . _ . . _ . - - _ _ _ _ -_ _ ~ . _ _ _ . _ _ . _ _ . . -
Yp 5~ O (2 c.G::.eG M bbl . 43 -( Ere M . \t., %-7 @.3 C2 M s n W bF S* . ESCALATED ENFORCEMENT
- PANEL QUESTIONNAIRE INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMENT PRE-PANEL I 4
j PREPARED BY: R. L.-Prevatte NOTE: The Section Chief is responsible for preparation of this questionnaire j and its distribution.to attendees prior to an Enforcement Panel. (This-information will be used by EICS to. prepare the enforcement letter and Notice, as well as the transmittal memo to the Office of Enforcement explaining and L justifying the Region's proposed escalated enforcement action.) , l l 1. ' Facility: St. Lucie j l l Unit (s):-l Docket Nos: 50-355 License Nos: DDR-67 !~ Inspection Dates: Auaust 28 - September 30, 1994 l Lead Inspector: R. L. Prevatte
-2. Check appropriate boxes:
- [X] A Notice of Violation (without "boilerplate") which includes the i recommended severity level- for the violation is enclosed.
i' [] This Notice has been reviewed by the Branch Chief'or Division Director and each violation includes the appropriate level of
, specificity as to how and when the' requirement was violated.
[X] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed, i l-j 3. Identify,the reference to the Enforcement Policy Supplement (s) that best j fits the violation (s) (e.g., Supplement I.C.2) I.D.3
- 4. What.is the apparent root cause of the violation or problem?
1.
. The aooarent root cause for the' event is a failure, on the part of i Operations Department manaaement. to provide control room operators with'
- - accurate information reaardina the implications of alianina the IC E Dumo to the IA3 bus. This failure appears to be the result of a failure THl3 DOCLMENT CONTAINS PREDECISIONAL INFORMATION--
)'
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMiiilitRATGit l i r - , . - - - - . , . . - . , ,
i i i ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE , to recoanize the noted limitations as they were described in IR 94-12.
- 5. State the message that should be given to the licensee (and industry)
- through this enforcement action.
l A thorouch, thouahtful review of conditions adverse to safety must be conducted followina identification of such conditions. C& &&las-&^ *^,' \ l 6. . Factual 'information related to the following civil penalty escalation or 4 mitigation factors (see attached matrix and i 10 CFR Part 2, Appendix C, Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the. discovery of the violation?
Was it self-disclosing? Was it identified as a result of a ! generic notification?) 1 The violation was identified by the resident inspector duri g_g 1 control room tour. i
- b. CORRECTIVE ACTION: Although we expect to learn more information -l regarding corrective action at the enforcement conference, I describe preliminary information obtained during the inspection i and exit interview. !
Upon identification of the subiect electrical lineuo, the licensee declared the 1A EDG out-of-service. A Nicht Order. correctly ; describina the imoact of the sub.iect electrical alionment was ! oromulaated. I What were the immediate corrective actions taken upon discovery of -l the violation, the development and implementation.of long-term corrective action and the timeliness of' corrective actions? See above. What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis? J
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List past violations that may be related to the current violation (include specific requirement cited and the date issued): e VIO 335.389/94-12-01. Inadeauate Corrective Action for a ' Previous Violation for Inadeouate Surveillance Testina of the C THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION-- IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADM'MISTRATOR 2
.. - - .. ~ - - . - . - . - - . . - . - . - . . . - . . . . . - -
i ' a ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE ICW Pumo. Reauirement: 10CFR50 Aco. B Criterion XVI. Corrective Action ! Date Issued: May 20. 1994 j Identify the applicable SALP category, the rating for this -
- . category and the overall rating for the last two SALP periods, as
- well as any trend indicated
SALP Cateaory: Operations - l The licensee has achieved SALP ratinas of I for the last two SALP
- periods. There have been an increasina number of events associated with Goerations in the cast six months
- however, these ,
events have not resulted in the identification of a clear trend. ; i ' ! d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities for the
- licensee to discover the violation sooner such as through normal I surveillances, audits, QA activities, specific NRC or industry
} notification,.or reports by employees? 3 The violation could have been orevented by a more comorehensive !
- response to the findinas of IR 94-12. The vulnerability at the 1 center of the current issue was discussed in that report.
i
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the-t violation identified during this inspection? If there were,
!- identify the number of examples and briefly describe each one. There were not multiple examples of this violation identified i durina this inspection oeriod. i l f. DURATION: How long did the violation exist? ! This violation occurred in an isolated fashion. The actual time.
- from initiation of the sub.iect electrical lineuo to the identification by the inspector, was aooroximately 3 hours. j ADDITIONAL COMMENTS / NOTES
1 2. l i j 1 1 1
- THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 3 4 f j
ESCALATED ENFORCEMENT PANEL OUESTIONNAIf3E NOTICE OF VIOLATION 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, as implemented by approved FPL Topical Quality Assurance Report, TQR 16.0 revision 8,
" Corrective Action," required that, for significant conditions adverse to quality, action shall be taken to preclude repetition.
Contrary to the above, on August 29, 1994, the licensee was found to be operating the IC Intake Cooling Water Pump powered from the IAB bus. The configuration had been identified in NRC Inspection Report 335,389/94-12 as representing an electrical configuration for which Technical Specification surveillance testing for Emergency Diesel Generator operability had not been satisfied. Specifically, load shed testing of the IAB bus, while aligned to the IA3 bus had not been performed as required by Technical Specification 4.8.1.1.2.e.3.a and 4.8.1.1.2.e.5.a. The report also discussed a 35 day period in 1993 when a similar electrical configuration on Unit 2 resulted in operation without the 2B Emergency Diesel Generator being demonstrated operable. While the licensee developed a Night Order to alert Unit 1 operators to the limitations of the subject electrical lineup, the Night Order failed Thus, the to properly describe the impact of the alignment on the unit. licensee's corrective actions failed to prevent the recurrence of establishing electrical plant configurations which failed to satisfy Technical Specifications.
**THis DOCUMENT CONTAINS PREDECISION*.L INFORMATION--
IT CAN NOT BE 0!$ CLOSED OUTSIDE kRC WITHOUT THE 4 APPROVAL OF THE REGIONAL ADMINISTRATOR
L o 1 ! Operations Department ! 6t. 'Eucle Auclear Sotner Stant JHgljt @rber ^ i l DISTRIBUTION: bnit 1 Control Room Unit 2 Control Room
! OPS Support (D-13) Work Control Group
- pecialists Training 4
i i From: Operations Supervisor's Office Date: Aug 311994 l 1 To: All Operations Personnel i
- 1. Congratulations to Skip Ryley and Sid Pennington for qualifying SNPO'
! i f' '
- 2. Attached are:the procedural instructions for chronological log entries. All entries must be made at the time they occur. If you
- beccme aware of!an event after it occurs that needs to be logged, then enter the actual time you make the log entry. This shall be
~
4 preceded by thelworda Late Entry as outlined in the procedure. There shall be no exceptisus to this. l
- 3. Unit 1- Until the safeguards test is complete the 1C ICW or i 1C CCW should not be aligned to the A side electrically. If it is required to place the plant in this configuration the CCW or ICW pump and the 1A Diesel Generator shall be declared OOS.
- 4. Excellent job by all operators on the shutdown and start up of Unit 1 this past weekend.
- 5. Starting tomorrow on dayshift the NLO's will be accompanied on their rounds by supervisory personnel. See attached memo from Ed Benken detailing the rationale.
l
- 6. Effective immediately Mr. Charlie Marple will come off shift and assume the duties that I previously performed. Effective
. immediately Mr.l Chuck Ladd will assume Charlies' shift during his operations support time.
91 Y e - .. . _ . , _ _ . - , _.e. _ _ . _ _ .
- S h) C 3 5f,3 79 4 4-G -oi 1514 u 4 T
*g t
NOTICE OF VIOLATION Florida Power & Light Company Docket Nos. 50-335 and 50-389 St. Lucie 1 and 2 License Nos. DPR-67 and NPF-16 During an NRC inspection conducted on March 27 through April 23 1994, a violation of NRC requirements was identified. In accordance with the " General
~
Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C, the violation is listed below: 19 CFR 50, Appendix B, Criterion XVI, Corrective Action, as implemented
- by approved FPL Topical Quality Assurance Report, TQR 16.0 revision 8,
. " Corrective Action," requires that measures be established to assure that
, conditions adverse to quality, including deficiencies and deviations, be promptly identified and corrected. Contrary to the above, the licensee failed to take adequate corrective i actions for Violation 335,389/92-05-04 for failure to adequately surveillance test the ability of the "C" Intake Cooling Water (ICW) pump to energize following a loss of offsite power (LOOP). The licensee's corrective action, completed on March 3, 1992, included a revision to procedure OP 2-0400050, Periodic Integrated Test of the Engineered Safety Features. Test procedures OP 1-0400050 and OP 2-0400050 remained inadequate, in that, they did not verify proper C train ICW and Component Cooling Water (CCW) pump (swing pump) load shed and sequencing functions when powered from their alternate power supply busses. l On April 3, 1994, during post-modification testing, the 2C ICW and CCW pumps failed to load shed from the B-train safety bus following a LOOP. Subsequent licensee analysis ccncluded that the 2B EDG was capable of performing its design function. , This is a Severity Level IV violation (Supplement I). Pursuant to the provisions of 10 CFR 2.201, the Florida Power & Light Company ! is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555, with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident Inspector at the St. Lucie site, within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should i be clearly marked as a " Reply to a Notice of Violation" and should include for each violation: (1) the reason for the vic!ation, or, if contested, the basis , for disputing the violation, (2) the corrective steps that have been taken and the results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the date when full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, an order or demand for information may be issued as to why the license should not be modified, suspended, or revoked, or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extending the response time. Dated at Atlanta, Georgia this 20th day of May 19 94 . Y 0(20i f*
, - - . ~ . - . - . _ . . _ - - . - - - . - - - - . . - - . - . . -
+
J g. I 9 N - i .1 x 57 Lu c.s c f(2 R - M.{3?9 imt b @ sc, \ et 4 4 14 !; [. Preoperation Startup, Physic Testing ., erational st up The in ctor reviewed ed that results of the the MTC,, critical boron ) phys s testing and' ere well c entration, and ontrol elementTh( assimbly testing.rod indicaworthd that the MT ithin the acce nce criteria. care to bn ! was positive .56 pcm/ degree F requiring speci
- the operators in eactor power /Ta precautions control.
exercised i Manageme briefed operatio personnel on t The y ue of the contro ing reactor power nder these cond ions. s within the limi imposed by TS' .l.1.4. i s MTC i I' d. Unit 2' Failure to L.oad Shed Swing Pumps On April 3, the licensee was performing PC/M 183-293 retests-j involving verification that the ICW and CCW pumps would perform as i designed on loss of and restoration of AC power to the pumps' buses. L As part of the test, the 2AB bus carrying the C (swing) ICW and CCW l pumps was aligned to B-train safety bus 283 and the swing pumps were j ! . operated in lieuWhen of their B counterparts, which had been placed in the 2B3/2AB busses were then deenergized, the j
" pull-to-lock." However, the licensee i(
2B EDG loaded onto the bus, as designed. The 2C CCW and l noted that the 2AB bus did not properly load shed. I ICW pump supply breakers remained closed By design, and thein pumps this case, started immediately when the EDG breaker closed. the 2C'CCW and ICW pump supply breakers should open initially and then reclose in six'and nine seconds, respectively, after the EDG breaker closure. Operationally, the C pumps were designed to perform the functions their A or B train counterparts, including responding to ESF actuation signals, load shed signals, and starting in the same EDG The 2AB bus has been normally aligned to the A-train load blocks. safety bus. ! The licensee investigated the condition and found that a wire, required to properly load shed the 2AB bus when it The wire circuit in question was shown on control ; breaker cubicle. l wiring diagrams and electrical schematics and only affected the load , shed characteristics of the 2AB bus when powered from the B-train l safety bus. The licensee concluded that the wire had not been installed since unit construction and installed a wire the same day. The test was then concluded' satisfactorily. i The inspectors concluded that, whenever the 2AB bus was aligned to l the B-train safety bus, the failure would effectively move the swing pumps' starting delay from their design load blocks to the 0-second load block and would also use the EDG output breaker as the motor starter. These pumps being large loads prompted the inspectors The to l 3m evaluate the potential for EDG overload during a DBA. y inspectors discussed the matter with site engineering personnel, who l 1
' D Lw>G /pd. n - 3y "5r9 ti '4 - c 15 l
subsequently concluded .that the 28 EDG re l loss of offsite power and adding the C ICW and CCW pumps to th 0-second load block. C While the noted condition The represented inspector a cha ; pumps were aligned to the B-train safety bus. reviewed operating logs for 1993 and found that the12, Ct ICW pump
- aligned to the B train several times while Unit 2 was operating power, with the longest occurrence being from July 8 to Augu 1993. i 335,389/91-201-03, documented in IR 91-l Previous NRC Deficiency Itemfocused primarily on inadequate Unit 1 ;
! 201 on November 15, 1991, procedures, but statad: l 4 "In Unit 2, the C (ICW) pump was only tested while ; l' aligned to Train A such that the Train B power logic l and circuit interlock features In summary, and the C pump wasthe not SIAS contact ; were not tested. tested and could not be proven operable on ... Tra B in Unit 2." , was further reviewed on site by the NRC staff l b ' Deficiency 91-201-04 335,389/92-05-04, which was issued on l and was upgraded to violationThe violation focused on f ailure to adequatelyl April 22, 1992. verify the ability of the C ICW pump to energize following a simulated loss of offsite power as required by TS surveillan i requirements 4.8.1.1.2.e.4. 92-05-04 stated:
"The 'C' pump portions of ECCS testing procedures for both units were revised to adequately test the'C'loss of offsite Intake This included an upgrade of l power functions.
Cooling Water pump and Component Cooling W 1 March 3, 1992." 2-0400050 Rev 15, " Periodic Integrated The inspectors reviewed OP f Test of the Engineered Safety Features," Rather, of the 2AB bus when powered from the B-train safety bus. the 2AB busThe and swing pumps were aligned to the A-train s inspector reviewed various revisions of this ( for the test. I procedure and noted that no testing, with regard circa to the sw had been conducted from the time of original procedure issueRev 26, 1992. 1984] until Rev 12, issued on March LOOP test of the 2C ICW and CCW pumps when powered bus. The procedure, with Rev 15, was most recently used on M j 16, 1994, during the ongoing Unit 2 outage. l
/
4 Q 4 M2 M . L.m . 6.
. W 6b -3M%ir9 16 /
not perform LOOP testing of the swing pumps when powered from t J' bus. Yg 4 On Unit 1, the swing pumps have been normally aligned to the B-train , safety bus. The licensee performed visual inspections The and verified inspector that a similar deficiency did not exist on Unit 1.1-0400050, R reviewed OP Engineered Safety Features," and found that the same failure to adequately test load shed capability existed; however, the failure involved not testing the IC swing ICW and CCW pumps when powered from the Unit 1 A-train safety bus. The current events demonstrated that the The inadequate corrective action for the above findings. licensee inadequatehad taken l preoperational and surveillance testing, with re k 2AB bus inability to load shed properly. action resulted in the i the periods in which the C ICW pump was aligne ' 1993. Violation 335,389/92-05-04 (Failure to Adequately Test the C ICW - This current failure to meet NRC requirements is Pump) is closed. identified as violation 335,389/94-12-01, Inadequate Corrective Action for a Previous Violation for Inadequate Surveillance Testing of the C ICW Pump. In Summary: l o Theperformanceofrodworthandauxilfaryfeedwatertestingwere , ' excellent. / /
'/cerning physics 4esting and po W Managemen attention was noted l /e- modific ion testing.
- action for a evious e One iolation involved in equate correcti pump.
vi ation for inadequat surveillance te ing/ of the C I
- 5. aintenance Obsepation (62703) ed safety-rela systems Station maintenance activities 4nvolving seleertain that th were
) andcomponentswereobserveA(reviewedtoa The followl items were
'th requirement . es were 2 conducted in accordance eview: LCOs w e met; activi i
considfred during thi ; functional sts and/or accpaplished using pp' proved procedur returning to onents or syste to calibrations wereAerformed prior ere maintaine , activities wer Mervice; quality' control records re accomplished qualified perso el; parts an materials used as were implement ] properly cer ified; and radiol gical controatermine the st us of , i ork requests wer reviewed to k required. outstand g jobs and to ens re that prio ty was assigne to safety-
O I:PL P 0. Box 128 Ft. Pierce. (L 34954-0128 E'! " Eu' 410:35 JUN 151994 L-94-133 10 CFR 2.201 i I U. S. Nuclear Regulatory Commission Attn: Document Control Desk i Washington, D. C. 20555
'Re: St. Lucie Units 1 and 2 Docket Nos. 50-335 and 50-389 Reply to Notice of Violation InsDection ReDort 94-12
! Florida Power and Light Company (FPL) has reviewed the subject inspection report and pursuant to 30 CFR 2.201 the response to the notice of violation is attached. j very truly yours, , a
. / 2 J. H. Goldberg 3
President - Nuclear Division JHG/JWH/kw Attachment j cc: Stewart D. Ebneter, Regional Administrator, USNRC Region II Senior Resident Inspector, USNRC, St. Lucie Plant
- DAS/PSL #1109-94 0
c 9 sie m an F9L Greno comeen,
Re: St. Lucio Unita 1 cnd 2
. Docket Nos. 50-335 and 50-389 '. !
Reply to Notice of Violation i Insnection Renort 94-12 VIOLATION: - 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, as l implemented by approved FPL Topical Quality Assurance' Report, TQR l 16.0 revision 8, " Corrective Action, " requires that measures be I established to assure that conditions adverse to quality, including deficiencies and deviations, be premptly identified and corrected. i Contrary to the above, the licensee failed to take adequate corrective actions for Violation 335,389/92-05-04 for failure to adequately surveillance test the ability of the "C" Intake Cooling Water (ICW) pump to energize following a' loss of offsite power . (LOOP). The licensee's corrective action, completed on March 3, 1992, included a revision to procedure OP 2-0400050, Periodic Integrated Test of the Engineered Safety Features. Test procedures 4 OP 1-0400050 and OP 2-0400050 remained inadequate, in that, they did not verify proper C train ICW and Component Cooling Water (CCW) pump (swing pump) load shed and sequencing functions when powered + from their alternate power supply busses. On April 3, 1994, during post-modification testing, the 2C ICW and CCW pumps f ailed to load shed from the B-train safety bus following 4 a LOOP. Subsequent licensee analysis concluded that the 2B EDG was , capable of performing its design function. *
RESPONSE
- 1. REASON FOR VIOLATION
' FPL concurs violation that a violation existed. The root cause of this was an inadequate procedure. The Safeguards procedure failed to adequately test the swing pumps. Specific corrective action was taken for the first violation. However, the scope of the review following the initial violation was 4 not expanded sufficiently to ensure adequate testing of the i swing pumps in all possible configurations. Additional testing is required to ensure that the intent of Technical Specification Surveillance Requirements is met.
- 2. CORREunvz STEPS TArm AND THE RESULTS Ammysu A. LOOP testing, load shedding and subsequent reloading of the C ICW and CCW Pumps aligned to their alternate power supply busses was performed as part of post-modification testing for the ICW and CCW Pumps. This test 7 was completed on April 3, 1994. Completion of this tt .ing put Unit 2 in full compliance with the Technical t
Specification.
. _ . . _ . . _ . . . _. _._._._._._..__. _ .__m ._ . _ . _ _ _ . _
J 1 i . R2: St. Lucie Units 1 cnd 2 ! , Docket Nos. 50-335 and 50-389 Reply to Notice of Violation J Insnection Renort 94-12 I i ' l. , .B.' An Operations Night Order was issued on May 3, 1994 stating to all Operations personnel that during the 18 j j month Unit 1 Safeguards testing the "C" ICW and CCW Pumps ; 4
) were not tested while aligned to their alternate power 1
, supply busses. The Night Order states the "C" ICW and ;
)
CCW Pumps are inoperable while aligned to their alternate ! power supply busses. This Night order will be in'effect until the surveillance test is performed on the Unit 1 l 1 i alternate power supply buss load shedding relays. Unit ! 1 was in full compliance on May~ 3, 1994 by ! i administratively declaring the 1C ICW and 1C CCW Pumps . l i inoperable if aligned to the alternate power supply busses. ; ! 3. CODDECilvz STEPS TO AVOID run-- VIOTATIONS $ { A. An interim test is being developed which will test the i Unit 1 alternate power supply busses load shedding . l' relays. This test will be completed prior to declaring i the 1C ICW and 1C CCW pumps operable if aligned to the j s alternate power supply busses. i f
- B.-
A complete review will be performed on the Swing Bus i i Testing for both Unit 1 and Unit 2 Safeguards testing i procedures to ensure compliance with the Technical Specification Surve.illance Requirements. The Unit l' : i' Safeguards testing procedure Periodic Intearated Test of the Enoineered Safety Features OP#1-0400050 will be ! i revised to ensure testing of the Unit 1 alternate power ! supply busses load shedding relays prior to performance i of the next scheduled 18 month surveillance testing 3 during the Cycle 13 refueling outage. i i The Unit 2 l Safeguards testing procedure Periodie Intearated Test of ! l-j the Enaineered Safety Features OP#2-0400050 will be revised to ensure testing of the Unit 2 alternate power ! j i supply busses load shedding relays prior to performance i i of the next scheduled 18 month surveillance testing during the Cycle 9 refueling outage.
- 4. . Full compliance was achieved April 3, 1994 on Unit 2 with the
, completion of Corrective Action 2.A. above. ! _ Full compliance was achieved May 3, 1994 on Unit 1 with the j completion of Corrective Action 2.B. above. 4 i j i !4 4
-, -,,-n,, ,
9
^] .e j
t
@perations Department 6t. Y.ucie Auclear Sotner Stant I Afgfjt @rber )
DISTRIBUTION: Unit 1 Control Room Unit 2 Control Room
- OPS Support (D-13) Work Control Group 1
- ' gapecialists uning i
! From: Operations Supervisor's Office Date: 03 May 1994
- To: All Operations Personnel l
- l. Unit 1- During the pull to lock testing on Unit 2 a wiring i
i error was identified which would cause the swing 4160 pumps to start on the zero load block. This was corrected and is
- considered adequately survielled. However this revealed that
, during the 18 month safeguards testing the swing components are
- j not tested while aligned to their abnormal electrical side. This i
means that we 6an not take credit for the swing components on ( Unit 1 when aligned to the 'A' side. This will be in effect until j .l the safeguards test is performed on Unit i during the next ( 3
- outage.
~ . )
l 2. Attached is a finding from our last INPO evaluation. This is j worth while reading material for all operators. j 3. The following cleaning is to be performed tonight: l Peak shift- 1A and 1B Closed Blowdown Cooling Pumps
- 2Aland 2B SSWLU Pumps j 1A and 2A CCW Pumps
- Mid Shift- 2A and 2B Closed Blowdown Cooling Pumps ;
1A and 1B SSNLU. Pumps ( 1B and 2B CCW Pumps
- 4. The midnight maintenance status meeting that is chaired by the NPS starts again beginning tonight.
, .~.-
.p . JUN 2 F 1994 Docket Nos. 50-335, 50-389 License Nos. DPR-67, NPF-16 Florida Power and Light Company , ATTN: Mr. J. H. Goldberg. , President - Nuclear Division ! P. O, Box 14000
- Juno Beach, FL 33408-0420 Gentlemen:
SUBJECT:
NRC' Inspection Report No. 50-335/94-12 AND 50-389/94-12 Thank you for your response of June 15, 1994, to our Notice of Violation, issued on May 20, 1994, concerning activities conducted at your St. Lucie i facility. We have evaluated your response and found that it meets the ; requirements of 10 CFR 2.201. We will examine the. implementation of your ; corrective actions during future inspections. 3 We appreciate your cooperation in this matter. Sincerely, ORIGINAL SIGWO 8tY DAVID M. V'ReF.U.I - David M. Verrelli, Chief 1 Reactor Projects Branch 2 j Division of Reactor Projects j cc: D. A. Sager ) Vice President St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce, FL 34954-0128 H. N.'Paduano, Manager Licensing and Special Programs : Florida Power and Light Company P. O. Box 14000 Juno Beach, FL 33408-0420 C. L. Burton Plant General Manager St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce, FL 34954-0128 cc: Continued see page 2 Giz ew wM- - 4 <
__ _ _ . _ . _ . . _ . . . _ _ . _ . _ _ _ _ - ~ . _ . . . _ . . _ _ _ _ _ _ . _ _ . _ . _ - . _ - . _ _ 1 l l l I'
$[ l T .h hb \ \
- A I
i ELECTRICAL POWER SYSTEMS l_ SURVEILLANCE RE00!RiMENTS'(Continued) l i i
- c. By sampling new fuel in accordance with ASTM 04057-81 prior to aedition to the storage tanks and:
- 1. By verifying in accordance with the tests specified in ASTM 0975-81 prior to addition to the storage tanks that the sample has:
! a) API Gravity within 0.3 degrees at 60'F or a specific j gravity of within 0.0016 at 60/60*F, when compared i to the supplier's certificate or an absolute specific j ' gravity at 60/60'F of greater than or equal to 0.83 but less than or equal to 0.89 or an API gravity of 60*F of greater than or equal to 27 degrees but less than or equal to 39 degrees. b) A kinematic viscosity at 40'C of greater than or equal to 1.9 centistokes, but less than or equal to 4.1 centistokes, if gravity was not determined by comparison with the supplier's certification. c) A flash point equal to or greater than 125'F, and . ! I d) A clear and bright appearance with proper color ' when tested in accordance with ASTM D4176-82.
- 2. By verifying within 31 days of obtaining the sample that the other properties specified in Table 1 of ASTM D975-81 are !
met when tested in accordance with ASTM D975-81 except that ' the analysis for sulfur may be performed in accordance with ASTM 01552-79 or ASTM D2622-82.
- d. At least once every 31 days by obtaining a sample of fuel oil from the storage tanks in accordance with ASTM D2276-83 and verifying that total particulate contamination is less than 10 mg/litar when i
checked in accordance with ASTM'02276-83, Method A, or Annex A-2.-
- e. At least once per 18 months during shutdown by:
i
- 1. Subjecting the diesel to an inspection in accordance with
-/
/ '
y/ procedures prepared in conjunction with its manufacturer's recommendations for this class of standby service. [ 2. Verifying generator capability to reject a load of greater p'J-g[y 4
- s. . than or equal to 600 hp while maintaining voltage at 4160 1 420 volts and frequency at 60 1 1.2 Hz.
p 3. Simulating a loss of offsite power by itself, and: a) Verifying deenergiration of the emergency busses x and load shedding from the emergency busses. ST. LUCIE - UNIT 1 3/4 8-S' Amendment No. 53, 103
ad H J5
\
({1 d L) , 7 .). i 1 - C-ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) b) Verifying the diesel starts on the auto start signal ****, i energizes the emergency busses with permanently connected loads withio 10 seconds, energizes the auto-connected ! l shutdown loads through the load sequencer and operates j i for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, , l the steady-state voltage and frequency of the emergency I l; l busses '. hall be maintained at 4160 + 420 volts and d 60 + 1.2 Hz during this test. 1
- 4. Verifying that on an ESF actuation test signal (without loss-of-offsite power) the diesel generator starts **** on the l auto-start signal and operates on standby for greater than or equal to 5 minutes. The steady state generator voltage i and frequency shall be 4160 + 420 volts and 60 + 1.2 Hz
! within 10 seconds after the auto-start signal; the generator , i voltage and frequency shall be maintained within these limits I during this test.
- 5. Simulating a loss-of-offsite power in conjunction with an l ESF actuation test signal, and j
a) Verifying deenergization of the emergency busses and load shedding from the emergency busses. f i i b) Verifying the diesel starts on the auto-start }, signal ****, energizes the emergency busses with permanently connected loads within 10 seconds, i energizes the auto-connected emergency (accident) l loads through the auto-sequencer and operates for i greater than or aqual to 5 minutes while its generator i i is loaded with the emergency loads. After energization, } 1 the steady-state voltage and frequency of the emergency i busses shall be maintained at 4160 + 420 volts and l 60 + 1.2 Hz during this test. l' c) Verifying that all automatic diesel generator trips, ! i except engine overspeed and generator differential, are automatically bypassed upon loss of voltage on ! ; the emergency bus concurrent with a safety injection l signal. I l I 1 1
- ****This test may be conducted in accordance with the manufacturer's i
4 recommendations concerning engine prelube period. i j h ST. LUCIE - UNIT 1 3/4 8-6 Amendment No. 52, In3 l ) i i
O k A -~ s Q %, j$* ~ Q,
-n r= j -
.a .
A . A-s . l I 1 l 4 l
r October 18, 1994 Florida Power & Light Company ATTN: J. H. Goldberg President - Nuclear Division P. O. Box 14000 Juno Beach, Florida 33408-0420
SUBJECT:
NRC INSPECTION REPORT NOS. 50-335/94-20'AND 50-389/94-20 Gentlemen: This refers to the inspection conducted by R. L. Prevatte of this office on August 28 - September 30, 1994. The inspection included a review of activities authorized for your St. Lucie facility. At the conclusion of the inspection, the findings were discussed with those members of your staff . identified in the enclosed 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, violations or deviations were not identified. Your attention is invited to an unresolved item identified in the inspection report. This matter will be pursued during future inspection. In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter and its enclosure will be placed in the NRC Public Document Room. Should you have any questions concerning this letter, please contact us. Sincerely, Orig signed by George A. Belisle for David M Verrelli, Chief
. Reactor Projects Branch 2 Division of Reactor Projects Docket Nos. 50-335, 50-389 License Nos. DPR-67, NPF-16
Enclosure:
NRC Inspection Report cc w/ encl: See page 2 0FFICIAL COPY hgM4_p
1 FP&L 2 I 1 cc w/ encl:- j D. A. Sager l Vice President 1 St. Lucie Nuclear Plant i P. O. Box 128 ; Ft. Pierce, FL 34954-0128 H. N. Paduano, Manager Licensing and Special Programs Florida Power and Light Company P. O. Box 14000 Juno Beach, FL 33408-0420 C. L. Burton Plant General Manager St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce, FL 34954-0128 Robert E. Dawson Plant Licensing Manager St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce, FL 34954-0218 Harold F. Reis, Esq. Newman & Holtzinger 1615 L' Street, NW Washington, D. C. 20036 John T. Butler, Esq. Steel, Hector and Davis 4000 Southeast Financial Center Miami, FL 33131-2398 Bill Passetti Office of Radiation Control Department of Health and Rehabilitative Services 1317 Winewood Boulevard Tallahassee, FL 32399-0700 Jack Shreve Public Counsel Office of the Public Counsel c/o The Florida Legislature 111 West Madison Avenue, Room 812 Tallahassee, FL 32399-1400 cc w/ enc 1: Continued see page 3 l I
FP&L 3 cc w/ enc 1: Continued > Joe Myers, Director . Division of Emergency Preparedness Department of Community Affairs 2740 Centerview Drive Tallahassee, FL 32399-2100 ; Thomas R. L. Kindred l County Administrator , St. Lucie County 2300 Virginia Avenue 1 Ft. Pierce, FL 34982 : Charles B. Brinkman l Washington Nuclear Operations I ABB Combustion Engineering, Inc. 1 12300 Twinbrook Parkway, Suite 3300 Rockville, MD 20852 Distribution w/ encl: K. Landis, RII J. Norris, NRR G. A. Ha11strom, RII PUBLIC NRC Resident Inspector U.S. Nuclear Regulatory Comm. 7585 South Highway A1A Jensen Beach, FL 34957-2010 l F' RII W hin KLa s 10/14/94 10A /94
p mary UNITED STATES
'o NUCLEAR REGULATORY COMMISSION p S REGK)N11 101 MARIETTA STREET, N.W., SUITE 2000
$ j ATLANTA, GEORGIA 3GR2::o199
\ * .* *
- j#
Report Nos.: 50-335/94-20 and 50-389/94-20 Licensee: Florida Power & Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.: 50-335 and 50-389 License Nos..- DPR-67 and NPF-16
. Facility Name: St. Lucie 1 and 2 1
Inspection Conducted: August 28 - September 30, 1994 Inspectors:
,R.
b L. Pfevatte, Senigt Resident io oV Da'te Signed
)
Inspector I % M. S. Miller, Residenp Inspector in /W ic y Date Signsd I. Sd1 ' to lu 'Q*/ R. .Schn,Seactorg4 neer Dite Signed
"'1f C /W: M. Sartor, Senior adiation ll /
Date/Si'gned V Speciali Approved by: .
. - N~ / k K. 'D.'LandisMhief Date Sigrfed !
Reactor Projects Section 2B l Division of Reactor Projects l
SUMMARY
Scope: This routine resident inspection was conducted onsite in the areas i of plant operations review, maintenance observations, surveillance i observations, plant support, followup of previous inspection findings, and other areas. 1 Inspections were performed during normal and backshift hours and on 4 weekends and holidays. l Results: In the areas inspected, violations or deviations were not I identified. An unresolved item involving 1A Emergency Diesel Generator Operability Concerns and Control Room Logkeeping (URI , 335/94-20-01) was identified, paragraph 3.c.
, - . - . . -. .. _ . - . . - . - .. - -.-. - . - . - ~ ~ - - - - . . . ~ - 4
- 2 ,
2
- Plant Operations arer.:
2 The licensee conducted plant operations in.a safe manner during the . inspection period. The inspectors identified an r " olved item :
- involving operators placing operable emergency dit 2 i generator IA !
j in a lineup (with the safety-related swing bus powered from it) for
- j which the TS-required surveillance testing had not been performed.
j Also, control room log entries on this item appeared to be
. inaccurate. The inspectors will assess the safety significance of ;
1 this item after the licensee determines and performs the required , i testing during the refueling outage that is scheduled to begin on i i October 31,-1994., During plant tours on Unit 1, inspectors noted a significant number of steam and water leaks. They also identified a i Weakness involving valve position indicating devices and the procedures and training provided to_ operators on how to verify valve
- positions.
- Maintenance and Surveillance area:
! During the inspection period, the licensee conducted maintenance in l ! a safe and effective manner. Inspectors noted that the accuracy and l , ranges of required test equipment were not always specified in l l procedures. The licensee experienced a near miss involving work on , i the wrong train by electricians. This appears to have been the i result of less than fully effective work control and communications. l
; Inspectors also found that plant personnel have not been trained on 2
their Individual Plant Examination and were not using it as a part :
- of work planning and scheduling. In addition, inspectors identified .
l several minor deficiencies in the area of labeling. l i : Plant Support area: The plant's support functions continued to be effective. The licensee modified their process and procedures for accountability . during a site evacuation. Drill results verified that this can now , be accomplished in acceptable time limits. 3 4 i ) 4 i
, - - . . ~ . . . . ,
~
REPORT DETAILS
- 1. Persons Contacted Licensee Employees l
R. Ball, Mechanical Maintenance Department Head ! W. Bladow, Site Quality Manager i L. Bossinger, Electrical Maintenance Department Head ' H. Buchanan, Health Physics Supervisor C. Burton, St. Lucie Plant General Manager R. Church, Independent Safety Engineering Group Chairman i R. Dawson, Licensing Manager l D. Denver, Site Engineering Manager i J. Dyer, Maintenance Quality Control Supervisor H. Fagley, Construction Services Manager P. Fincher, Training Manager R. Frechette, Chemistry Supervisor i
- J. Goldberg, President Nuclear Division K. Heffelfinger, Protection Services Supervisor J. Holt, Plant Licensing Engineer ,
' G. Madden, Plant Licensing Engineer i J. Marchese, Maintenance Manager C. Marple, Assistant Operations Supervisor l K. Mohindroo, Site Engineering Supervisor W. Parks, Reactor Engineering Supervisor C. Pell, Outage Manager j L. Rogers, Instrument and Control Maintenance Department Head ! D. Sager, St. Lucie Plant Vice President : J. Scarola, Operations Manager and Acting Plant General Manager J. Spodick, Operations Training Supervisor l D. West, Technical Manager
- J. West, Site Services Manager C. Wood, Operations Supervisor W. White, Security Supervisor Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Personnel
- R. Prevatte, Senior Resident Inspector
- M. Miller, Resident Inspector
- R. Schin, Reactor Engineer, Region II
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
1
~
2 e 2. Plant Status and Activities
- a. Unit 1 Unit 1 began the inspection period at 65 percent power. Power had 1
been reduced on August 27 to perform a leak repair on the DEH system and replace expansion joints on the CW piping. The turbine was taken off line on August 28 to repair the leak in the Digital Electro-Hydraulic System. Repairs were completed and the unit returned to power on the afternoon of August 28. The unit operated at approximately 65 percent power until the CW system repairs were , completed on September 2. The unit then returned to and operated at essentially 100 percent power until power was reduced to approximately 65 percent on September 29 to nennit work on TCW IA heat exchanger and to clean condenser waterboxes. These repairs were completed on September 30 and the unit was in the process of returning to full power at the completion of the reporting period.
- b. Unit 2
- Unit 2 operated at essentially 100 percent power throughout the inspc
- : tier, period.
- c. NRC Activity During the period, W. J. Tobin and L. C. Stratton of the Division of Reactor Safety and Safeguards, Region II, were onsite from September 26 through September 29. Their inspection results are documented in IR 335,389/94-21. J. H. Moorman and S. J. Cahill of the Division of Reactor Safety also were on site for Licensed Operator Requalification exams during the same period. Their inspection results are documented in IR 335,389/94-19. W. M. Sartor of the Division of Reactor Safety and Safeguards was on site on September 30 to evaluate a site evacuation drill. His inspection results are contained in this report.
'3 . Plant Operations (71707, 37551)
- a. Plant Tours The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate. The inspectors also detendined that excess equipment or material was stored properly, and combustible materials and debris were disposed of expeditiously. During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic restraint settings,.various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of fire fighting equipment, and instrument calibration dates. Some tours were conducted on backshifts, weekends, and holidays. The
~
- i i I 3
1 ; frequency of plant tours and control room visits by site management j
- was noted. l The inspector accompanied NL0s on their daily rounds of Unit 1 ,
3 reactor building and turbine building on September 21 and 22. It f 1 took each operator two to two and one half hours-to make their i ! required rounds, examine equipment and spaces for abnormal i i conditions, and perform tasks such as making flow or level 1 adjustment on equipment, sumps, or tanks. The inspector observed i i that the operators performed general inspections of each assigned j
~
j area. They appeared to be alert and demonstrated a F,d practice of
- touching and feeling equipment as needed to detect v erheating or j excessive vibrations. ;
} The inspector questioned the operators extensively about previous l equipment problems, how negative trends are detected, ecuipment ' functions and operation, frequency of rounds, plant and equipment ! labeling, and the responsiveness of maintenance and other support [ organizations to equipment failures a'nd management and supervisory i j expectations. Both operators appeared to be very knowledgeable in
- all the above areas. They also appeared to be conscientious and motivated and proud of their plant and its past accomplishments.
The inspector found the overall condition of the plant and observed , equipment to be satisfactory. He did note approximately 25 steam ; i and water leaks that required repair. In each case these had been-i previously identified by plant personnel and a PWO tag'was attached.
- The unit is scheduled for a refueling outage on October 31. When these items were' discussed with the plant manager, he stated that
! all leaks and temporary leak repairs will be worked during the refueling outage. { j The inspectors conducted a main flowpath walkdown of the Unit 1 HPSI i- and LPSI systems, the Units 1 and 2 AFW systems, and support systems. Valve, breaker, and switch lineups as well as equipment conditions were randomly verified both locally and in the control , room. No deficiencies were identified on the AFW systems. j i During the main flowpath walkdown for the Unit 1 HPSI and LPSI i systems, the inspector identified a licensee weakness involving ' j i valve position indicating devices and the procedures and training j given to operators on how to verify valve positions. AP 0010120, Conduct of Operations, directed operators to determine the position of MOVs for system lineups by using the stem position indicators or , position pointers, by a functional test (i.e., flow through the :
; valve), or by having the ANPS determine an alternate method. The !
i inspector found four local MOV position indicators to be unusable . (i.e., illegible or indicating 50% open when the valve was closed); i
; this was about 15% of all the M0V position indicators inspected.
h The inspector asked the auxiliary operator on shift to show how he would determine th.e position of HPSI header MOVs in the Unit 1 lower i i i ~
4 4 l level' pipe tunnel for a system lineup (including valves with unusable position indicators). The operator stated that the local valve position indicators were known to be unreliable so he would not use them. He showed the inspector position indicating lights in i a nearby room that he would use. He showed how, for those valves that did not have nearby position indicating lights, he would use I grease marks on the valve stem to tell valve position. The ; inspector noted that procedure AP 0010120 did not address the use of ' position indicating lights or grease marks on the valve stem. 'The inspector concluded that the licensee's maintenance of MOV local i position indicators did not support AP 0010120 and placed the operators in the position of having to " work around" that deficiency. The inspector also concluded that the procedures and training of operators on how to determine MOV valve positions were . weak. ! 4 The inspector identified another " operator work-around" on MOV valve l
- position: procedure OP 1-0410020, HPSI/LPSI - Normal Operation, l required MOV V3653, IB/1C HPSI Pump Discharge Cross-Tie, to be locked open. However, the inspector found it to be closed, with the handwheel locked and the breaker tagged open on an administrative clearance. There was no clearance tag on the valve, and a review of the clearances in the control room indicated that the valve position was not addressed by a clearance. The NPS and ANPS stated that the )
desired position for the valve was closed, since the IC HPSI pump l was inoperable and had been abandoned in place (with the-motor ! removed) for several . years. i The inspector reviewed the last system lineup that had been performed, in May 1993, and found that operators had not verified the position of V3653, but had stated (incorrectly) on the system lineup sheet that V3653 was on an administrative clearance. The , inspector concluded that OP l-0410020 was in error on the required ! position of V3653 and that cperators had been erroneously working around this procedure error. The inspector also found that several valves had locks on their handwheels that were not required by OP l-0410020. Also, the plant operating drawings for the HPSI and LPSI systems showed some valve handwheel locks but did not show many others. The licensee stated that they had recognized a deficiency in the area of documentation for valve handwheel locks, and had begun to correct the operating procedures and drawings. The inspector reviewed AP l-0010123; Administrative Control of Valves, Locks, and Switches; rev. 96; dated September 1, 1994. For periodic verification of the status of locked valves, AP 1-0010123 directed operators to use control room or other remote indication as appropriate. The procedure also provided a more thorough and correct listing of locked valves, including reasons why the locks were on the valves. The inspector ! concluded that the licensee had made a good start on correcting the
. weakness with procedure and drawing documentatior, of locked valves. . _ _ _ _ . _ _ _ _ _ . _ _ _ __.__ __ _ _ _ _ _ _ _m - _ - _
a . During the HPSI and LPSI systems walkdown, the inspector observed about 23 deficiencies with equipment or procedures (i.e., unusable valve position indicators, valve packing leaks, unsealed electrical i flexible conduits, room lights not working, and an instrument air leak, all without PWO tags; handwheel locks not shown on system , lineup procedures; and other errors in system lineup procedures). The NPS and ANPS were responsive in initiating maintenance work requests and procedure changes to address these deficiencies.
- b. Plant Operations Review The inspectors periodically reviewed shift logs and operations
- records, including data sheets, instrument traces, and records of equipment malfunctions. This review included control room logs and
, auxiliary logs, operating orders, standing orders, jumper logs, and equipment tagout records. The inspectors routinely observed operator alertness and demeanor during plant tours. They observed ) and evaluated controi room staffing, control room access, and operator performance during routine operations. The inspectors conducted random off-hours inspections to ensure that operations and security performance remained at acceptable levels. Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures. Control room annunciator status was verified. No deficiencies were observed. During this inspection period, the inspectors reviewed the tagout (clearance) on reactor drain pump 2A 2-94-09-068. No deficiencies were identified.
- c. Technical Specification Compliance Licensee complianu with selected TS LCOs was verified. This included the review of selected surveillance test results. These verifications were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by 4
review of completed logs and records. Instrumentation and recorder traces were observed for abnormalities. The licensee's compliance with LC0 action statements was reviewed on selected occurrences as they happened. The inspectors verified that related plant procedures in use were adequate, complete, and included the most ! recent revisions. During a Unit I control room tour conducted at approximately 4:00 p.m. August 29, the inspector noted that the IAB 4.16 KV bus was aligned to the 1A3 4.16 KV bus and that the IC (swing) ICW pump was operating in lieu of the 1A ICW pump. The lineup had been made to support maintenance activities in the Unit 1 intake bays. The 2AB bus was normally aligned to the 1B3 bus and was the source of power for the IC ICW pump. During a postulated LOOP, the IA3 bus would be 4 powered by the 1A EDG. The electrical lineup in question was effected at 1:26 p.m. on August 29.
1
. \
6 As documented in IR 94-12, the IC ICW pump has never been tested for load shedding capabilities when powered with the IAB bus aligned to the IA3 bus. As a result, TS surveillances 4.8.1.1.2.e.3.a and . 4.8.1.1.2.e 5.a, which verified load shedding capabilities in response to LOOP and LOOP /SIAS signals, had never been satisfied. As these surveillance tests formed part of the bases for 1A EDG operability, the operability requirement of TS LCO 3.8.1.1 was not satisfied when the 1AB bus was aligned to the IA3 bus with the IC 4 ICW pump operating. During a postulated DBA involving a loss of offsite power, the ICW pumps were designed to load shed from their respective busses and sequence back onto the busses in 9 seconds. The design feature was provided to prevent EDG overload conditions during reenergization of IE busses. A failure of an'ICW pump to l load shed would have the effect of moving the pump from the 9 second l to the 0 second EDG load block, increasing tho EDG's starting load. The inspector questioned the ANPS as to the operability of the 1A EDG, given that the 1AB bus was aligned to the 1A3 bus. The ANPS stated that the electrical lineup in question resulted in IC ICW pump inoperability and that the pump had been declared inoperable accordingly. The ANPS stated that the basis for his determination was a Night Order which stated that the pumps powered from the'1AB bus could not be taken credit for when aligned to the IA3 bus. A caution tag had been hung on a IA3-to-1AB breaker handswitch to that ! affect. The inspector raised his concern regarding EDG. operability to Operations Department management. After discussions with engineering and other plant personnel, Operations management directed that the 1A EDG be declared inoperable based upon the noted failure to perform required surveillance testing. The 1A EDG was declared inoperable at approximately 5:00 p.m., however the licensee chose to establish the time of inoperability at 1:26 p.m., the time the noted electrical lineup was established. In response to this issue, the licensee performed an evaluation of l 1A EDG performance for the subject electrical' lineup. As the load shedding capabilities cf the IC ICW pump had never been tested, the analysis assumed that the pump would not load shed, effectively moving the pump to the O second load block of the 1A EDG. The licensee found that the combin tion of the 1A HPSI pump (400 HP) and the IC ICW pump (600 HP) alone was enough to exceed the motor starting capability of the'EDG, described by Figure 3 of the EDG system DBD as approximately 980 HP. The licensee subsequently reported that r, more detailed evaluation of 1A EDG accident loading was being conducted. The inspector concluded-that, in a Night Order dated May 3,1994, the licensee failed to accurately convey to operators the findings of IR 94-12, paragraph 4.d, which stated, in part:
"On Unit 1, the swing pumps have been normally aligned to the B-train safety bus...The inspector...found that the same failure to adequately test lead shed capability existed; however, the failure
I 1 7 involved not testing the IC ICW and CCW pumps when powered from the j . Unit 1 A-train safety bus. h [The failure to properly test the load shedding characteristics of F the Unit 2. swing pumps)...resulted in the 2B EDG not being ,. demonstrated operable for the periods in which the C ICW pump was [ aligned to the B-train safety bus..." l In response to this issue, the licensee generated a new Night Order
- which correctly described the impact of aligning operating 1AB bus
- pumps to the IA3 bus. The failure to adequately convey operational
- limitations to control room operators resulted in a recurrence of operating a Unit's electrical plant in a configuration for which EDG
- operability had not been. demonstrated. ,
f At approximately 11:00 a.m. on August 31, the inspector reviewed the : i Unit I control room log and found the following: { e An entry, made at 1:26 p.m. on August 29, described the change 1 in the electric plant detailed above. At the end of the l , description, the entry stated ".. 1A EDG 00S." < 1 ! e An entry, timed at.2:26 p.m. on August 29, stating "1C AFW Pump operable, offsite power available, redundant 'B' components
- operabl e. "
. As the 1A EDG was declared inoperable at approximately 5:00 p.m. as
- a result of the inspectors observations, the inspector questioned
- control room' operators about the log entries (the operators
! -questioned had been on watch when the electrical lineup was changed , on August 29). The operators had no knowledge of the log entries ) i detailed above. The inspectors discussed the issue with the j Operations Supervisor, who stated that the entries were most ! probably made by the. peak shift ANPS on August 29 to reflect the
- fact that the EDG was declared inoperable. The Operations j Supervisor also stated:
j e The time of EDG inoperability had been declared to be the time when the 1AB bus was aligned to the 1A3 bus (1:26 p.m. on [ August 29). 1
- e The entry describing the availability of offsite power supplies j~ and the operability the IC AFW pump and B side ECCS components had been made to satisfy AS (b) of TS LCO 3.8.1.1, which i required such checks when an EDG was declared inoperable. The j entry was said to take credit for normal control room walkdowns and log entries in the RCO, control room and out-of-service .
logs. e The method of log entries in this case was not in accordance with site procedures. i
[ l'.
- 8 i
l The inspector discussed.the matter with the ANPS who had been on t- duty during the_ peak shift on August 29. The ANPS stated that he did make the log entries in question and.that the' entries were the
- ' result of a-discussion with the Operations Supervisor, who had j directed the ANPS to make log entries describing inoperability of-
- the 1A EDG. .The ANPS stated that his. understanding of the .
Operations Supervisor's directions was.that.the logs from the day ahift of August-29 should be augmented to include the EDG < lE inoperability. The ANPS stated that, in the course of the i discussion, he informed the.0perations Supervisor that, if < inoperability was taken from 1:26 p.m., then the one hour period for i completion of AS (b) of TS LC0 3.8.1.1 had been exceeded. The ANPS
- stated that the Operations Supervisor directed that RCO board 3
walkdowns and various control room logs be taken credit for as satisfying the AS, a practice wMch had been used in the past under similar circumstances. Finally, the ANPS stated that he had made the noted log entries with hesitation, but believing that the actions were made.under the direction of the Operations Supervisor. I The' Operations Supervisor acknowledged the discussion, stating that he had directed the ANPS to declare the 1A EDG inoperable effective at 1:26 p.m. on August 29. The Operations Supervisor stated that it was not his, intent that the previous shift's logs be altered and ! that an apparent miscommunication had existed between himself and l the ANPS. ; The inspector reviewed the Bases for TS LC0 3.8.1.1 which, with regard to.the verification of offsite power and component l operability required in AS (b) of the LCO, stated:
"The term verify as used in this context means to administratively !
check by examining logs or other information to determine if certain ! components are out-of-service for maintenance or other reasons. It 1 does not mean to perform the surveillance requirements needed to ' l demonstrate the OPERABILITY of the component." l Consequently, the inspector found that the methodology employed for 1 making the 2:26 p.m. log entry of August 29 was in keeping with the TS. However, the inspector found that the time logged for the activity was misleading both in the statement of when the activity occurred and by whom the activity was performed. Specifically: e The portion of the August 291:26 p.m. log entry stating that t the 1A EDG was 00S, was misleading in that the EDG was declared 00S at approximately 5:00 p.m. that day. Further, the entry did not reflect the activities of the day shift operators. i e The August 29 log entry of 2:26 p.m., stating that offsite power sources were available and that. the IC AFW pump and redundant.B side components were operable, was misleading in that the subject verifications were not performed on that shift. j
l 3 I l 9-l In response to this event, the licensee issued a Night Order on August 31 reiterating procedural requirements for maintaining logs chronologically. i The inspector reviewed Administrative Procedure 0010120, Revision j ! 63,." Conduct of Operations," and found that Appendix F covered log i
- keeping. Section 2 of the appendix stated, in part, "... entries are i
- to be made in chronological order. Where this is NOT possible, i entries shall be preceded by the words Late Entry." The ANPS's !
l actions, relative to the modification of the logs of the previous i shift were counter to the requirements in the procedure, j Th'e licensee has scheduled testing of the 1AB bus's load shedding ! capabilities (when aligned to the 1A3 bus) for the upcoming refueling outage. The inspectors will follow the testing at that time. The combined issue of 1AB bus load shed testing and the noted
- discrepancies in control room logkeeping will be resolved following
! the performance of the subject surveillance tests and will be ~ tracked as an unresolved item (URI-94-20-01, IA EDG Operability Concerns and Control Room Logkeeping). As a result of this issue, the licensee designated a team to review the adequacy of integrated safeguard; testing. The testing is performed each refueling outage and used to satisfy the 18-month EDG surveillance test requirements of TS. The team will complete this review and incorporate any necessary changes to the Unit 1 Integrated Safeguards Test procedure prior to the Unit'l refueling outage, currently scheduled for~1 ate October. Parallel to the licensee's review of integrated safeguards testing, the inspector began a review of selected portions of the test procedure. With respect to the ICW pumps, the inspector found the following: e The licensee's testing, performed in accordance with OP 1-0400050 revision 32, " Periodic Integrated Test of the Engineered Safety Features," appeared to adequately test the 1A and IB ICW pump control circuitry as describec on schematic diagrams 8770-B-326 sheets 832 (revision 8) and 833 (revision 7). l e The licensee's testing per OP 1-0400050 appeared to inadequately test the IC ICW pump control circuitry as described on schematic diagram 8770-B-326 sheet 834 (revision
- 7) in the following regards:
e Relay 27X-3 contacts have not been adequately tested for LOOP conditions when the IC pump is aligned electrically to the IA3 bus. This is a restatement of the findings of IR 94-12. The testing of this feature would demonstrate load shedding capabilities of the IC ICW pump when aligned
1 e 4 ' 10 to the IA3 bus and is a requirement of TS 4.8.1.1.2.e.3.b and 4.8.1.1.2.e.5.b.
~e 4YAl relay contacts, which prevent IC ICW pump automatic starts under SIAS conditions if the 1A ICW pump is running i and the IC ICW pump is aligned electrically to the IA3 bus, have not been-tested. The testing of this feature :
t would assure'that a start of a second ICW pump would not occur during the loading sequence of the 1A EDG with the IC ICW pump aligned electrically to the IA3 bus under SIAS ;
^
conditions. e 3YA2 relay contacts, which provide for a sequenced IC ICW start if-the IC ICW pump is operating in lieu of the 1A ' ICW pump, have not been tested. The testing of this feature would demonstrate the automatic sequencing feature ; of the IC ICW pump end is a requirement of TS 4.8.1.1.2.e.3.b and 4.8.1.1.2.e.5.b. Additionally, the inspector noted the following conditions, which were transmitted to the licensee and were being considered in the licensee's ongoing review: The load sequence timing for the 1A and IB ICW pumps was found : to be 9 seconds; the timing for the IC ICW pump was 10 seconds. ! The timing for the IC ICW pump was selected to tring about a standby start of the IC pump upon receipt of a SIAS signal unless the operating (IA or IB) ICW pump starts first.. The l timing tolerance provided for these sequencing times are provided.in OP 1-0400050 as +/- 1 second. The inspector found that this tolerance allowed for an unfavorable stackup which ; could result in the IC pump acceptably starting in 9 seconds i with the IA/IB pump acceptably starting in 10 seconds. As r.c . interlock was provided to prevent a IA/lB pump start if the IC . pump started first, an unfavorable stackup resulting from . setpoint drift could result in two ICW pumps starting nearly simultaneously. , l In discussing this issue with the licensee, the inspector was ; directed to maintenance procedure 1-0910055, " Periodic Test of , Automatic Load Sequence Relays," which provided instructions for testing and setting the time delay relays which provide ICW pump sequencing. The procedure specified tolerances of .5 : i seconds which, while more favorable than the tolerances specified in OP 1-0400050, still allowed for identical pump starting times. e The' inspector noted that, should the 1A/1B ICW pump trip following a LOOP /SIAS start, the timing sequence for the IC pump would begin. This scenario would lead to 1 1C ICW pump < start 10 seconds after the IA/1B pump trip, effectively adding 8 O I _- . . . -.. . _ _ -- -, . - - . ~ , _ . .<._ -. -.
11 a load to another load block. The EDG's ability to support the load is being evaluated by the licensee. The inspectors will continue to follow the licensee's review of the adequacy of integrated safeguards testing and will review the licensee's responses.to the issues raised above. No violation 'or deviation was identified in the ?lant Operations area. One unresolved was identified: URI 335/94-20-01, JA Emergency Diesel Generator Operability Concerns and Control Room Logkeeping.
- 4. Maintenance and Surveillance (62703, 61726)
- a. Maintenance Observations Station maintenance activities involving selected safety-related systems and components were observed / reviewed to ascertain that they were conducted in accordance with requirements. The following items were considered during this review: LCOs were met; activities were accomplished using approved procedures;. functional tests and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as required. Work requests were reviewed to determine the status of outstanding jobs and to ensure that priority was assigned to safety-related equipment. Portions of the following maintenance activities were observed:
(1) NPWO 63/2068 HPSI Flow Transmitter Calibrations The inspector witnessed portions of HPSI flow transmitter calibrations conducted August 9. Work was performed per the noted NPWO and I&C procedure IC 1-1400064F revision 29,
" Installed Plant Instrument Calibration (Flow)."
The calibration process required that differential pressures be established with an air source ano thst transformer output be measured with a mil 11 ammeter. Differential pressure was initially measured with an analog Heise gage with a range of 0-830" H2 O and minimum subdivisions of 1" H20. Technicians performing the calibration exhibited good radiological controls practices and HP involvement with initial swipes and surveys was good. . A number of M&TE-related problems were experienced during work on the first transmitter. The first ammeter employed in the process yielded suspect results and was eventually replaced. The use of a regulated air supply to establish required differential pressures proved difficult to control accurately (due to a lack of sensitivity in the regulator) and was replaced with a hand pump. The hand pump i
i I 4 12 ; provided the required sensitivity, however the technician f controlling pressure stated that the could not read the Heise - gage to the. required le*lsi of accuracy. The calibration sheet : required pressures be established with an accuracy of .1" H 2O . l with no tolerances established and the inspector agreed that ! the minimum subdivision size and denomination made the required
' level of accuracy impossible to achieve (the inspector i estimated the distance between. subdivisions of the gage at approximately 1/16"). -The technicians then replaced the analog l Heise gage with a digital model accurate to .1" H 20. .The inspector observed a series of calibration checks with the new ,
test arrangement and found it adequate to the task. The inspector concluded that the I&C personnel performing the calibration had acted conscientiously in dealing with the M&TE problems which developed. However, the inspector found that : the difficulties encountered ir, establishing the required ; differential pressures could have been prevented in a number of i ways , 1 e The calibration sheet established a series of required differential pressures which were specified to .1" _H2 0, ; while the acceptance criteria for transmitter output was in whole milliamps. Had the differential. pressures been expressed in whole inches of water, the analog Heise gage . could have been employed for the celibration. j e The governing procedure specified that required test equipment would be specified on individual calibration 3 sheets. While the subject sheets described parameters to ' be measured and ranges required, it did not specify test equipment specifically. Had the need for a digital Heise gage and a hand pump been specified, several changes in ' required M&TE could have been avoided. e No tolerances were established for the independent variable (differential pressure). This forced technicians to conclude that the analog Heise gage was inadequate to obtain the required accuracy. While, the inspector conc 1UJed that the governing procedure had several shortcomings, it was adequate to direct the activities of the I&C personnel performing the calibration. The inspector provided his observations to the I&C Supervisor responsible for the calibration. (2)_ NPWO 63/2403' 1A2 SIT Level Loop Calibration Check The inspector witnessed portions of this calibration check, ! which was initiated when sporadic changes in IA2 SIT level were ! noticed by operators. The level transmitter in question had ) 1 l l
13 been previously blown down in containment, where a small amount of water was found.in the transmitter's dry reference leg. The calibration' check involved the input of a test signal to the
'IA2 SIT level versatile circuit and a comparison of input to output.
The inspector verified that M&TE was within its calibration period. I&C personnel performing the calibration check had appropriate procedural guidance on the job scene and performed the test well, with good communications between themselves and control room operators. The calibration check indicated that the level. indicating loop was performing within its calibration. specifications. I&C determined that the observations of the control room operators was most probably due to the water that was found in the transmitter's reference leg.
-(3) Wrong Train Near Miss On September 14, during normal control' room rounds, the inspector.noted that clearance 1-94-09-050 had been placed on the Unit 1 RWT suction valve (MV-07-1A) to train A HPSI, LPSI, and CS pumps to permit VOTES testing on the motor operated valve. Removal of a ECCS train for service is permitted by TS 3.5.2 with a 72 hour AS.*
Since the licensee's IPE shows HPSI as the highest risk system, the inspector questioned the need to accomplish this task at power. He also asked if any precautionary measures had been put in place to protect the remaining ECCS train. They stated that no additional precautions other than required by TS had been implemented. The inspector questioned control room operators on their familiarity with their IPE as to which systems were the most critical. The operators did not appear to be very familiar with the plant's IPE. Tua inspector met with the plant manager and discussed operator training on the IPE. The discussion also covered how and why a-decision was made to remove critical systems from service to perform VOTES testing with the unit.at power. The plant manager stated that the plant needed to complete VOTES testing and had accelerated this effort to complete the requirements of. NRC GL 89-10. He also said.that an engineering study had been done which showed that the small risk associated with this testing was overshadowed by the overall improvement in safety. The inspector discussed this stpdy with engineering and found that the study had determined that the testing could be accomplished without a significant increase in risk. The study had not attempted to prioritize valves and determine if low risk valves should be done at power and high risk valves done during a refueling outage, l
._ . _ s
. i l 1 l 14 At approximately 10:00 a.m., two electricians assigned to I partially disassemble the valve met the VOTES. testing supervisor at the RWT. lThe'V0TES testing supervisor had not' attended the prejob briefing and was under the false impression that the testing was to be done on MV-07-1B instead of MV-07-1A which is adjacent. The supervisor pointed out to the-electricians that the lock was still attached to the valve's handwheel which would prevent testing of the valve. The work crew called the control room and requested that an operator remove the lock. When the operator arrived and compared the j valve tag with the electrician's work order, he found that the ' electricians were starting to work on the wrong valve. The , work which had been ~ started on the valve did not render it ! inoperable. l 1 The licensee is performing. a detailed evaluation of this l incident to determine the root cause and required corrective , action.- Since this was the second event in the past six months ) involving electricians, all work involving V0TES testing was 1 stopped antil this event could be evaluated and additional controls and training could be accomplished. This event was a near miss that could have resulted in i rendering both trains of ECCS inoperable with the unit at ) power. The plant manager and staff appear to realize the ! significance of this item and are taking corrective actions. The-inspector will monitor these actions as they are completed. b., Surveillance Observations i Various plant operations were verified to comply with selected TS requirements. Typical of these were confirmation of TS compliance for reactor coolant chemistry, RWT conditions, containment pressure, control room ventilation, and AC and DC electrical sources. The inspectors verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, LCOs were met, removal and restoration of the affected components were accomplished properly, test results met requirements and were reviewed by personnel other than the individual directing the test, and.that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel. The following surveillance tests were observed: (1) OP 1-0700050, REV 44, " Auxiliary Feedwater Periodic Test" The inspector witnessed portions of this surveillance test performed on.the 1A and IB AFW pumps. NL0s performing the test had appropriate portions of the procedure in hand. Preoperational checks of the pumps were satisfactory and M&TE , used for the test was properly calibrated. The inspector noted ) good attention to detail on the part of an NLO in correcting another NLO who had recorded pump suction and discharge
__ _ _ __. _ _ _ . . _ _ _ _ . _ _ - -__.___._.__m.._ 4 # i l . I i 15 i
- pressures before the procedurally-required 5 minute run time !
had been satisfied. The data was discarded and new data was
- j. taken following the 5 minute run time. The results for both pumps were satisfactory.
(2) OP 2-0400053, REV 18, " Engineering. Safeguards Relay Test" I s-l The inspector observed the performance of a majority of the ! semiannual Engineering Safeguards Relay Test on Unit 2 on :
- September 7 and 16. This surveillance tests the .
- - instrumentation and relays for safety injection (SIAS), :
- Containment Spray (CSAS), Containment Isolation (CIAS), Main '
> Steam Line Isolation (MSIS), and Containment Sump Recirculation ! (RAS). This test is considered a load threatening and j sensitive test so no other significant tests are conducted at j the same time. 1 In the prejob briefing, the ANPS stressed the prerequisites and precautions associated with the tests. He clearly defined the assignment of each individual and covered the steps to take if a malfunction or unexpected result should occur. In addition, the procedural requirements for infrequently performed i evolutions and the jumper lifted lead procedure were also reviewed. The rule for good repeat-back communications was ! also stressed. The NPS and I&C supervisor were present during 1 the job briefing and provided oversight and supervision as l needed during the test. ] This test generally takes eight to ten hours to cM0ete and since other critical tests were also scheduled, it was completed to an appropriate break point and the remainder of the test was scheduled for the following week. The test went well and all components operated correctly. Two temporary procedure changes had to be initiated due to ; equipment out-of-service and/or plant conditions. These were j correctly processed. Overall, the test crew, operations, and I&C maintenance displayed teamwork, excellent communications, and good procedural compliance during the test. The inspector did identify that on several instances the ANPS directed the operators to restore equipment in a different sequence than shown in the procedure. This is permissible but could result l in a step being missed. The licensee agreed to review these ! steps and incorporate human factors improvements as needed. The inspector also identified that six test pushbuttons in actuation cabinets had been labelled with a marking pen. I&C submitted PW0s 94013863 and 94013921 to have permanent labels made and installed.
16 (3) OP l-1200054, REV 19, RAB Fluid Systems Periodic Leak Test 1 The inspector accompanied engineers of the licensee's Technical Staff during inspections of selected Unit I fluid systems . , during system operation. The inspections were targeted at the early identification of leaks. The inspector observed the preparations for a LPSI walkdown, which included walking down the system beforehand to identify all accessible piping runs and a delineation of responsibilities among the 3 engineers involved. Inspections were carried out expeditiously, with good ALARA practices displayed. The inspections were successful in identifying a number of minor packing and union leaks. The inspector found this practice.to be-noteworthy in its potential for early identification of failures in fluid ' system integrity and to control contamination.
- c. Licensee Action on Previous Maintenance Findings (92902)
(Closed) IFI 50-335,389/92-05-01, Seismic Qualification of Racked Out Circuit Breakers This IFI had been initiated in response to'an inspector observation on March 9, 1992, of a IB ICW breaker that was removed from its switchgear housing and was sitting unrestrained in front of other safety-related switchgear. The inspector reviewed the licensee's REA 92-104, 4KV Circuit Breaker Seismic Condition in Racked Out Position, dated March 10, 1992, and the related engineering evaluation, JPN-PSL-SECS-92-012, Seismic Qualification of 4KV Switchgear with Breakers in the Racked Out Position, dated August 19, 1992. The engineering evaluation concluded that racked-out breakers will not adversely affect the seismic qualification of the 4KV switchgear or introduce any seismic interaction concerns. -The inspector found the evaluation to be timely, detailed, and reasonable. The engineering evaluation did not address breakers that were removed from their switchgear housing. The inspector discussed this with the electrical maintenance department head who stated that, in response to this issue, maintenance department expectations that any removed breakers be stored away from the front of safety-related switchgear had been stressed to electrical maintenance personnel. The inspector toured safety-related electrical switchgear rooms and found several removed breakers stored in the corner of a switchgear room and no removed breakers in front of safety-related switchgear. This. item is closed. No violation or deviation was identified in the Maintenance and Surveillance area.
17
'5. Engineering (37551)
- Licensee Action on Previous' Engineering Findings (92903) ,
(Closed) IFI 50-335,289/92-20-01, Heat Load Calculations and Resultant FSAR Changes L This IFI was opened to follow NSSS vendor containment analysis heat load . calculations that were due to be completed by December,1992, and -
= subsequent FSAR changes. The inspector reviewed the'. heat load calculations and verified that they were in the Unit I and Unit 2 FSARs. . ,
i The inspector also reviewed the licensee's engineering evaluafions JPN- ' i- PSL-SENP-93-017 and'JPN-PSL-SENP-93-018, St. Lucie Units l'& 2 Safety Evaluations for the Updated LOCA Containment Analysis, dated April 29, 1993. The inspector found the engineering evaluations to be adequate. This item is closed. No violation or deviation was identified in the Engineering area.
- 6. Plant Support -(71750) {
- a. Fire Protection During the course of their normal tours, the inspectors routinely examined facets of the Fire Protection Program. The inspectors reviewed transient fire loads, flammable materials storage, housekeeping, . control hazardous chemicals, ignition source / fire risk reduction efforts, fire protection training, fire protection system surveillance program, fire barriers, fire brigade qualifications, and QA reviews of the program. No significant deficiencies were noted.
- b. Physical Protection.
The inspectors verified by observation during routine activities that security program plans were being impi mented as evidenced by: proper display of picture badges; searching of. packages and . 1 personnel at the plant entrance; and vital area portals being locked and alarmed. No deficiencies were identified.
- c. Radiation Protection The inspectors verified that HP policies and procedures were being l followed. This included routine observation of HP practices and a 4 review of area radiation survey, RWPs, postings, and equipment operation. No deficiencies were identified.
1
;_ 18 e
! d. Licensee Action on Previous Plant Support Findings (92904)- i j (Closed) IFI 50-335,389/94-04-02, NRC c'bservation of a site accountability drill in 1994. i- [ The senior resident inspector and a regional emergency preparedness inspector observed the licensee's site accountability drill I . conducted on September 30,.1994. The drill was initiated from the i . control room with a drill message for an alert. The TSC and OSC. j were activated while nonessential personnel . reported to staging i areas outside the protected area. At the site area emergency level, personnel evacuated the owner controlled area-(in reality the l personnel left the site with shift completion which approximately coincided with the SAE). The drill was well controlled and met the i designated objectives. The inspectors determined an adjusted time ! for site accountability of approximately 39 minutes considering the [ time for exiting the protected area, security providing the list of personnel reported to be on site and the cross checking of.the list 3 with facility accountability forms. The accountability identified [ three personnel as unaccounted, one of which was a controlled input. The drill was considered to be on the outer edge of meeting the j desired approximately 30 minutes. Improvements to the system were
- - discussed that should result in better times. This item is closed.
- No violation or deviation was identified in the Plant Support area.
- 7. Other Areas Evaluation of Licensee Self Assessment (40500) 4 The inspectors attended two FRG meetings during the inspection period.
On September 6, the FRG reviewed six procedure changes, an instruction i manual change, one temporary change, and a plant change / modification. l Two of these items were returned to the presenter for additional , improvement and/or clarification. The meeting was conducted in a ! professional manner and the plant manager gave explicit comments on his
- expectations of quality for plant procedures. On September 8, the FRG 3 discussed a planned PC/M for ten HFA relays and several procedural l- changes. A construction group procedure' discussed at the previous days 1 FRG was again sent back for further rework to ensure that it provided the same guidance used by plant maintenance to perform essentially the same task. .The plant manager again reiterated his expectations for all plant
- l. i construction procedures.
~
)
! No violation or deviation was identified. j .- 8. Exit Interview 2 The inspection scope and findings were summarized on September 30, 1994, 3 with those persons indicated in paragraph 1 above. The inspector i j- described the areas inspected and discussed in detail the inspection j 2 e t i . _ . . _ . . _ _ _ _ _ _
- - - _ _ _ _ - -[
~
19 results listed below. Proprietary material-is not contained in this report. Dissenting comments were not received from the licensee. , Item Number Status Description and Reference 335/94-20-01 open URI - 1A Emergency Diesel Generator Operability Concerns'and Control Room Logkeeping, paragraph 3.c. 335,389/92-05-01 closed IFI - Seismic Qualification of Racked Out Circuit Breaker, paragraph 4.c. 335,289/92-20-01 closed IFI - Heat Load Calculations and Resultant FSAR Changes, paragraph 5. 335,389/94-04-02 closed IFI - NRC Observation of Site Accountability, paragraph 6.d.
- 9. Abbreviations, Acronyms, and Initialisms AC Alternating Current .
AFW Auxiliary Feedwater (system) AFWS Auxiliary Feedwater System ALARA . As Low as Reasonably Achievable (radiation exposure) ANPS Assistant Nuclear Plant Supervisor AP Administrative Procedure AS Action Statement ATTN Attention CCW Component Cooling Water CFR Code of Federal Regulations CIAS Containment Isolation Actuation Signal CS Containment Spray (system) CSAS Containment Spray Actuation System l CW Circulatory Water DBA ' Design Basis Accident DBD Design Basis Document DC Direct Current ! DEH Digital Electro-Hydraulic (turbine control system) DPR. Demonstration Power Reactor (A type of operr. ting license) ECCS Emergency Core Cooling System , EDG Emergency Diesel Generator I FPL The Florida Power & Light Company FRG Facility Review Group FSAR Final Safety Analysis Report ' GL [NRC] Generic Letter HFA A GE relay designation ! HP Health Physics HPSI High Pressure Safety Injection (system) ; I&C Instrumentation and Control l ICW Intake Cooling Water IFI [NRC)' Inspector Followup Item IPE Individual Plant Examination
4 + ' 20 IR (NRC] Inspection Report KV Kilovolt (s) LC0 TS Limiting Condition for Operation. LER Licensee Event Report LOCA Loss of Coolant Accident LOOP Loss of Offsite Power LPSI Low Pressure Safety Injection (system) M&TE Measuring & Test Equipment MOV Motor Operated Valve MSIS Main Steam Isolation Signal i MV Motorized Valve NLO Non-Licensed Operator No. Number
- NPF Nuclear Production Facility (a type of operating license)
NPS Nuclear Plant Supervisor NPWO Nuclear Plant Work Order ' NRC Nuclear Regulatory Commission NSSS Nuclear Steam Supply System , 00S Out of Service ! OP Operating Procedure i
- OSC Operations Support Center j PC/M Plant Change /Mocification i PWO Plant Work Order i QA Quality Assurance l RAB Reactor Auxiliary Building l RAS Recirculation Actuation Signal RC0 Reactor Control Operator REA Request for Engineering Assistance Rev Revision l- RII Region II - Atlanta, Georgia (NRC)
RWP Radiation Work Permit ' RWT Refueling Water Tank SAE Site Area Emergency
- SIAS Safety Injection Actuation Signal SIT Safety Injection Tank St. Saint TCW Turbine Cooling Water TS Technical Specification (s)
- TSC Technical Support Center UFSAR URI [NRC] Unresolved Item V0TES Valve Operation Test Evaluation System
1 1 EZCS STRFF EDEM 3RCILITY: r i =r == [] EEFEXEF D- e/uhe CRSE EOs ZE, 50: Ald====. 5,L: [i [1 ~-_':= - DRE TO 03:
's M R EOs ,
fw LRST m GF 33Fe=mm a V' / h h e/ W. 2EEPECTER: V)7<2L / Ve ra2E, STRET: want.
/ Amu efa . :
DITISICE: Mr v SECTZEN: w7 ( BDB M D[n 0&ZC
, s \
~.
EDtEE: ) 012s-. M M WA rx. 08 &fA ^ N P ,te"!sAA' ,bse sc4AL V s i Se'Ohd~ d> b wad 4 sdM& b& , w'- raah C C O
~
diks ,4G+! AZ M~i ' ok sof d m e a n. 6% % d- AL,n . inL W-W N a - o n4M a vvi& W . .', l 1 l 1
)
l
.w..__-,.---. . .-- ; .
.;L :,r m .
CM N SL: 559: CDs g . . . . ..... mg
(.
' i l
- i ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE 1 NOTICE OF VIOLATION i- 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, as implemented
- by approved FPL Topical Quality Assurance Report, TQR 16.0 revision 8, L " Corrective Action," required that, for significant conditions adverse 3
.to. quality, action shall be taken to preclude repetition.
l Contrary to the above, on August 29, 1994, the licensee was found to be i operating the IC Intake Cooling Water Pump powered from the IAB bus. 1 The configuration had been identified in NRC Inspection Report i 335,389/94-12 as representing an electrical configuration for which l Technical Specification surveillance testing for Emergency Diesel Generator operability had not been satisfied. Specifically, load shed testing of the IAB bus, while aligned to the IA3 bus had not been
- i. performed as required by Technical Specification 4.8.1.1.2.e.3.a and i 4.8.1.1.2.e.5.a. The report also discussed a 35 day period in 1993 when j l a similar electrical configuration on Unit 2 resulted in operation l 4 without the 2B-Emergency Diesel Generator being demonstrated operable.
} While the licensee developed a Night Order to alert Unit 1 operators to the limitations of the subject electrical lineup, the Night Order failed , 1 i to properly describe the impact of the alignment on the unit. Thus, the l licensee's corrective actions failed to prevent the recurrence of ! establishing electrical plant configurations which failed to satisfy i Technical Specifications. j
- -- _ _. 1 k
i/ ! ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE NOTICE OF VIOLATION l Unit 1 TS 6.8.1.a required that written procedures shall be established i and implemented covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A, paragraph i l.h includes administrative procedures for. log keeping. St. Lucie Administrative Procedure 0010120, revision 63, " Conduct of Operations," i Appendix F, " Log Keeping," stated that log entries were to be made in a i chronological order and that, where this was not possible, entries were l to be preceded by the words " Late Entry." Contrary to the above, on August 29, 1994, a Unit 1 Assistant Nuclear Plant Supervisor modified and appended Unit 1 control room log entries i made on a previous shift. The modifications were not annotated in any ] way and created a false impression of the activities of the previous
- shift.
I a
/ -
l ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE l NOTICE OF VI0tATION Unit 1 TS 6.8.1.a required that written procedures shall be established and implemented covering the activities recommended in Appendix A of ' Regulatory Guide l.33, Revision 2, February 1978. Appendix A, paragraph 1.h includes administrative procedures for log keeping. St. Lucie i Administrative Procedure 0010120, revision 63, " Conduct of Operations," Appendix F, " Log Keeping," stated that log entries were to be made in a chronological. order and that, where this was not possible, entries were to be preceded by the words " Late Entry." Contrary to the above, on August 29, 1994, a Unit 1 Assistant Nuclear Plant Supervisor modified and appended Unit I control room log entries - made on a previous shift. The modifications were not annotated in any , way and created a false impression of the activities of the previous ' shift. l i l l l l 1
- THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 9 ) J m _. __ ___ ____
___j
)
i
\
l f i 3
- ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE i
NOTICE OF VIOLATION 10 CFR 50, Appendix B, Criterion XVI,. Corrective Action, as implemented by approved FPL Topical Quality Assurance Report, TQR 16.0 revision 8,
" Corrective Action," required that, for significant conditions adverse to quality, action shall be taken to preclude repetition.
Contrary to the above, on August 29, 1994, the licensee was found to be operating the IC Intake Cooling Water Pump powered from the IAB bus. The configuration had been identified in NRC Inspection Report 335,389/94-12 as representing an electrical configuration for which Technical Specification surveillance testing for Emergency Diesel Generator operability had not been satisfied. Specifically, load shed testing of the 1AB bus, while aligned to the IA3 bus had not been performed as required by Technical Specification 4.8.1.1.2.e.3.a and 4.8.1.1.2.e.5.a. The report also discussed a 35 day period in 1993 when a similar electrical configuration on Unit 2 resulted in operation without the 2B Emergency Diesel Generator being demonstrated operable. While the licensee developed a Night Order to alert Unit 1 operators to the limitations of the subject electrical lineup, the Night Order failed to properly describe the impact of the alignment on the unit. Thus, the licensee's corrective actions failed to prevent the recurrence of ) establishing electrical plant configurations which failed to satisfy i Technical Specifications. l
--THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 4
f49nso S -4 ~ ENFORCEMENT ACTION WORKSHEET d#"/ PRELUBRICATION OF VALVES PRIOR TO ASME SECTION XI TESTING PREPARED BY:Joel T. Munday DATE: July 11, 1996 NOTE: The Section Chief of the responsible Division is responsible for preparation of this EAW and its distributton to attencees arter to an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and telepnene bridge numoer to attendees via e-mail (ENF.GRP. CFE. OEMAIL, JXL. JRG. SHL. LFO: approortate RI! DRP. DRS: approortate NRR, NMSS). A Notice of Violation (without "boilerplate") unten includes the recomended severity level for the violation is recuireo. Coptes of applicable Technical Specifications or license conditions cited in the Notice or other reference material
- needed to evaluate the proposed enforcement action are required to be encloseo.
This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and ) when the requirement was violated. Signature i Facility: St. Lucie Unit (s): 1, 2 i Docket Nos: 50-335, 50-389 License Nos: DPR-67, NPF-16 Inspection Report No: 50-335,389/96-11 i Inspection Dates: July 7 - August 3,1996 . l Lead Inspector: Mark Miller
- 1. Brief Summary of Inspection Findings:
An NRC inspector identified, through document review, that the Unit 1 ! containment spray flow control valve,1-FCV-07-1A, was being ! preconditioned prior to being tested. Specifically, prior to the l performance of the surveillance which verifies proper stroke-time of the i valve, lubrication was applied to the valve stem. Further inspection identified that three other containment spray valves were also prelubricated prior to being stroke-time tested. The licensee had noted in a QA assessment that this practice was occurring, however, it was not highlighted as significant nor was a STAR written to document its occurrence. The QA assessment indicated that there did not appear to be a correlation between frequency of lubrication and test performance. However, when informed by the inspector that this practice could result in not obtaining true as-found data and would not provide reliable trend information, the licensee agreed and revised the appropriate procedures to delete the practice. Violation 335/95-15-05 was issued documenting the fact that a STAR was not initiated as required by plant procedures. Corrective actions for this violation included documenting the event in STAR 951048 as well as revising the applicable procedures to remove the practice of D, b PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
prelubricating other valves prior to surveillance testing. In addition,
- STAR 951063 was written to. review other test and surveillance procedures to determine if similar conditions existed elsewhere. One additional valve was identified that might be impacted by this practice and that problem was also corrected. The licensee stated, in response to STAR 951063, that the PMs which lubricated the valves were performed along with the stroke-time surveillance because the surveillance was required as a PMT following the PM. By scheduling the PM to be performed prior to the surveillance the number of surveillances per. formed would be reduced. 10 CFR 50, Appendix B, Criterion XI, requires, in part, that testing required to demonstrate that systems and components will perform satisfactorily in service shall be performed under suitable
- environmental conditions. Prelubrication of valsas prior to performing stroke-time tests violates.this requirement and negates the vailidity of the test in assessing the operational readiness of the valve.
Proposed NOV 10 CFR 50, Appendix B, Criterion XI, requires, in part, that 2 test program shall be established to a>>ure that all test'.n; required to demonstrate that systems and components will perform satisfactorily in service is identified and performed in accordance with written test procedures. Test procedures shall include provisions for assuring that the test is performed under suitable environmental conditions. Contrary to the above, Administrative Procedures, AP-1-0010125A, revision 39 for Unit 1 and AP-2-0010125A, revision 43 for Unit 2, did not ensure that the procedures were performed under suitable environmental conditions. Specifically, the two aformentioned procedures directed that valves 1-FCV-07-1A,1-FCV-07-1B, 2-FCV-07-1A, and 2-FCV-07-1B be lubricated prior to being tested. This practice negated the ability to assess the operational readiness of the valves. v This is a Severity Level IV violation (Supplement I). 4 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
, . ~ . _ _ . _._ _ . _
- 2. . Analysis of Root.Cause
It appears that the surveillance procedures were revised in September, 1994 to include lubricating the valves prior to performance. The licensee's response to STAR 951063 indicated - that this~was done-as a means of reducirg the number of surveillances required to be performed. The licensee did not consider..the~effect this practice would have on the validity of
.the as-found data. This decision appears to.have been a result of
~
poor engineering judgement. - i i 3. Basis 'for Severity Level (Safety Significance): ! Severity Level IV: . Supplement I.D.3 which states, "A failure to meet regulatory requirements that have more than. minor safety or environmental significance."
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
EA 96-040, 1/22/96, Level III Base CP: Overdilution Event . EA 95-180, 8/4/95, Level III Base CP: Inoperable PORVs .
- 5. Identification Credit? ((nterYesorNo): No
- Consider following and discuss if applicable below:
O Licensee-identified D Revealed through event 0 NRC-io ntified D Mixed identification- 0 Missed opportunities Enter date Licensee was aware of issues requiring corrective action: September, 1996 when questioned by NRC inspector. Explain application of identified credit, who and how identified and ; consideration of missed opportunities: ' Although identified in a licensee QA assessment report, the licensee did not realize the significance until identified by NRC.
- 6. Corrective Action Credit? [ Enter Yes or No): Yes Brief summary of corrective actions:
Upon identification that this practice was unacceptable, the applicable procedures were revised to' delete the practice. Other plant. systems and procedures were reviewed to determine extent of condition with only one additional case being identified. This ; example was also corrected. ' l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE ;
'. Explain application of corrective action credit:
Corrective actions were completed quickly and included a generic j i 1 review of other systems, both by the engineering staff and QA. l 1
- 7. Candidate For Discretion? [See attached list] [ Enter Yes or No)
- No. !
Explain basis for discretion consideration: .
- 8. Is A Predecisional Enforcement conference Necessary?
(Enter Yes or No): No. Why: There is no additional information needed by the NRC and the licensee has corrected the condition. If yes, should OE or OGC attend? [ Enter Yes or No): Should conference be closed? [ Enter Yes or No): i
! 9. Non-Routine Issues / Additional Information:
1
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: (Ercs to provice) ::5ineensistent,ineiuoe:)
Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Message:
f g u g g ,j g , w sl... The licensee needs to consider all impacts that a procedure change could have on a system prior to making the change. ^dditicrcily, stre::s the . importance of as found trending of equipment performance.
-/&$ 5 e
ll PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l l i a
- 12. Recommended Enforcement Action:
Level IV violation.
- 13. This case Meets the criteria for a Delegated Case. [EICS - Enter Yes or No)
- 14. Should This Action Be Sent to OE For Full Review? ;rICS - Enter Yes or No)
. 1 i If yes why: ! l
- 15. Regional Counsel Review [EICstoobtain)
No Legal Objection Dated:
- 16. Exempt from Timeliness: [EICS)
Basis for Exemption: 1 Enforcement Coordinator: DATE: l l l l l l f PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i i
ENFORCEMENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION O Problems categorized at Severity Level I or II. O Case involves overexposure or release of radiological material in excess of NRC requirements. O Case involves particularly poor licensee performance. O Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with 01 regarding the case, whether or not the matter has been formally referred to 01, and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included. O Current violation is directly repetitive of an earlier violation. O Excessive duration of a problem resulted in a substantial increase in risk. O Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. O Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) O Licensee's sustained performance has been particularly good. O Discretion should be exercised by escalating or mitigating to ensure that the proposed civil penalty reflects the NRC's concern regarding the violation at issue and that it conveys the appropriate message to the licensee. Explain. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Enclosure 3 C. REFERENCE DOCUMENT CHECKLIST [X] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: 50-335,389/96-11 [X ] Licensee reports: STAR 951048, STAR 951063 [] Applicable Tech Specs along with bases: [] Applicable license conditions [X] Applicable licensee procedures or extracts AP-1-0010125A; AP-2-001012A [] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results [] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability [ .] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [X] Other miscellaneous documents (List): TIA 96-007 - Acceptability of Lubricating Valves Prior to Surveillance Testing PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
' * \ O L4 W . Of 4 7/N p""%4 ce v.u a,; 3 UNITED STATES j i NUCLEAR REGULATORY COMMISSION
- WASHINGTON, D.C. 20salwoot dd d8 /46
- h * * * * * ,/ 7. Jyk 96 JLL 10 All
- 46
^ 0' 5'A July 2,1996 ,
MEMORANDUM TO: Jon R. Johnson, Acting Director // "b Division of Reactor Projects, RII FROM: Frederick J. Hebdon, Director Project Directorate II-3 Division of Reactor Projects I/II, NRR
SUBJECT:
TECHNICAL ASSISTANCE REQUEST (TIA 96-007) REGULATORY ACCEPTABILITY OF LUBRICATING VALVES PRIOR TO SURVEILLANCE TESTING (TAC NOS. M95274 AND M95275) In a memorandum dated April 12, 1996, as a result of valve stroke timing practices at the St. Lucie Plants, you requested NRR assistance in evaluating the acceptability of lubricating valves prior to the performance of stroke I time testing. You also asked NRR to resolve a question as to whether the l purpose of the stroke time testing was to demonstrate current and past operability of a valve, current and future operability of a valve, or both. The Mechanical Engineering Branch (EMEB), NRR, has completed its review of these issues. A discussion of these issues and NRR's response to your questions is contained in the attached memorandum dated June 24, 1996. Docket Nos.: 50-335 and 50-389
Attachment:
As Stated cc w/ attachment: R. Cooper, RI W. Axelson, RIII ; J. Dyer, RIV
Contact:
L. Wiens, NRR\PDII-3 415-1495
' M S l l S p ej cg
f:.- June 24, 1996 l MEMORANDLM T0: Frederick J. Hebdon, Director
- Project Directorate II-3 Division of Reactor Projects I/II FROM
- Richard H. Wessman, Chief Mechanical Engineering Branch
, Division of Engineering '
SUBJECT:
TECHNICAL ASSISTANCE REQUEST (TIA 96-007) i REGULATORY ACCEPTABILITY OF PRELUBRICATING VALVES i (TAC Nos. M95274/M95275) ! In a memorandum dated April 12, 1996 Ellis W. Merschoff, Director, Division !- of Reactor Projects, Region II, discussed the determination by Region II
- inspectors that the licensee of the St. Lucie nuclear power plant had i lubricated a containment spray flow control valve prior to performing stroke 3 time testing under Section XI of the ASME Boiler & Pressure Vessel Code. The Region II inspectors considered this pre-lubrication to result in a nonrepresentative test of valve capabilities.
Region II requested the Office of Nuclear Reactor Regulation (NRR) staff to respond to spectfic questions on the acceptability of the licensee's actions in pre-lubricating valves prior to testing. Attached is our response to those questions. CONTACT: T. Scarbrough, DE/EMEB 415-2794 l Docket Nos.: 50-335 50-389
Attachment:
As stated cc w/ attachment: J. T. Wiggins A. F. Gibson G. E. Grant Distribution: Central Filac EMEB RF/CHRON LWiens RCrotecu Valve List DOCUMENT NAME: G:\SCARBROU\RHWLUBE and PRECOND Vo recef we a cosy of this doctment, fruficate in the has Cacepy w/o attachment /ersiosure E=Casy with attachment /enetesure N e We e OFFICE EME91DC 6 EMEB:DE 3 E NAME TScabrough RWess [ DATE $/8/96 l 14/96
/
0FFICIAL RECORD COPY ATTACHMENT bf '3 hh
i [. i REGULATORY ACCEPTABILITY OF PRELUBRICATING VALVES i PRIOR TO SURVEILLANCE TESTING j ! (TIA 96-007) l Technical Assistance Reauest j In a memorandum dated April 12, 1996, Ellis W. Merschoff, Director, Division j of Reactor Projects, Region II, discussed the determination by Region II
- inspectors that the licensee of the St. Lucie nuclear power plant had i
lubricated a containment spray flow control valve prior to perforising stroke-l time testing under Section XI of the ASME Boiler and Pressure Vessel (B&PV)
- tode. The Region II inspectors considered this pre-lubrication to result in a nonrepresentative test of valve capabilities. Therefore, Region II requested l 4 response to the-following questions
i
- 1. Is the practice of lubricating a valve prior to stroke-time testing acceptable under the regulations?
- ~
l
- 2. Is the purpose of stroke-time testing under ASME Section XI to demonstrate the current and past operability of a valve, the current and
{ future operability of a valve, or both?
- Evaluation l The NRC regulations in 10 CFR 50.55a require that nuclear power plant i licensees provide valves and pumps within the scope of Section XI of the i ASME B&PV Code with access to enable the performance of inservice testing of
! those valves and pumps for assessing operational readiness as set forth in Section XI of the ASME B&PV Code. Criterion XI, " Test Control," of Appendix B 3 to 10 CFR 50 requires that testing be performed under suitable environmental j conditions. The current Inservice Testing (IST) Programs at St. Lucie Units-1
- and 2 are based on the requirements of Section XI of the ASME B&PV Code,1986
! Edition, with approved relief to certain requirements. Article IWV-1000 of l ASME B&PV Code (1986 Edition), Section XI, states that it provides the rules ! and requirements for inservice testing to assess operational readiness of j certain Class 1, 2, and 3 valves in nuclear power plants, which are required i to perform a specific function in shutting down a reactor to the cold shutdown l condition, in mitigating the consequences of an accident, or in providing i overpressure potection. Subarticle IW-3417 of the 1986 ASME B&PV Code states that, if a valve fails to exhibit the required change of valve' stem or disk position or exceeds its specified ?isiting value of full-stroke time by this testing, the licensee , shall init.iate corrutive action immediately with the valve declared inoperative if thr. condition is not corrected in 24 hours. Generic Letter
.(GL) 89-04, " Guidance on Developing Acceptable Inservice Testing Programs," in Position 8 indicttes that, rather than delaying 24 hours, the licensee should make a decisic. en operability when the data is recognized as being within the required action range. GL 91-18, "Information to Licensees Regarding Two NRC Inspection Nanual Sections on Resolution of Degraded and Nonconforming ATTACHMENT
i Conditions and on Operability,' provides similar guidance on the timeliness of operability decisions based on test results. IWV-3417 also requires that the , test frequency be increased if a significantly longer stroke time is observed since the last test. Finally, IWV-3417 requires that any abnormality or i erratic action be reported. The St. Lucie IST Program Plan identifies no ! differences in interpretation of the NRC regulations or. ASME Code when stating > l that the inservice testing in the plan is to be performed specifically to I i verify the operational readiness of pumps and valves which have a specific l l
' function in mitigating the consequences of an accident or in bringing the reactor to a safe shutdown.
l More recent ASME codes and standards have repeated and amplified the l importance of evaluating the operability of valves during inservice testing. i For example, Subsection ISTC, " Inservice Testing of Valves in Light-Water l Reactor Power Plants," of the ASME Operation and Maintenance (0Mc) Code states j that it establishes requirements for inservice testing to assess the operational readiness of certain valves and pumps used in nuclear power i plants. Subsection ISTC 4.2.9 requires that the valve be ilmnediately declared l l inoperable if the valve exceeds the limiting values of full stroke time. i Subsection ISTC 4.2.4 also requires that any abnormality or erratic action be - { recorded and that an evaluation be made regarding the need for corrective i action. ? l The NRC regulations, and ASME codes and standards, clearly indicate that the i purpose of the inservice testing programs is to " assess" the operational ! i readiness of the valves and pumps. Article IWA-9000, " Glossary," of ASME B&PV { Code (1986 Edition), Section XI, defines " assess" as determining "by i evaluation of data compared with previously obtained data such as operating ; l data or design specifications." More generally, Webster's II New Riverside I i University Dictionary defines " assess' as "to appraise or evaluate." If maintenance is performed prior to inservice testing that ensures the I capability of a valve or pump to operate properly, the licensee's IST program > would be unable to evaluate the operational readiness of the component. "his is reinforced by the requirement in the ASME Code that, if the stroke-time ' limits are exceeded, the condition be corrected or the valve be considered inoperable. The St. Lucie IST Program Plan intent "to verify the operational readiness" is more specific regarding the purpose of the. testing to determine the capability of the valves to perfore their safety function. The ASME Code recognizes that routine preventive maintenance will be performed by licensees. In some instances, this maintenance may occur shortly before a scheduled test required by a licensee's IST program. The effect of this maintenance on the validity of the test to assess operational readiness should be evaluated. In Section 3.5, " Testing in the As-Found Condition," of NUREG-1482 (April 1995), ' Guidelines for Inservice Testing at Nuclear Power Plants,' the staff stated that the Code does not specifically require testing to be performed for components in the as-found condition except for safety and relief valves, but does not define as-found even in the context of safety and relief valves. In NUREG-1482, the staff noted its belief that most inservice testing is performed in a manner' that generally represents the condition of a standby component if it were actuated in the event of an accident (i.e., no pre-conditioning prior to actuation). , 2
, ____ - _ _ _.___ _ _ _ _ . _ _ __ _ __ _ _ _ _ - - - q ,
k* i ' i }' In NRC Information Notice 96-24 (April 25,1996), " Preconditioning of Molded-i { { Casa Circuit Breakers Before Surveillance Testing," the staff stated that the j practice of preconditioning solded-case circuit breakers (for example, by - lubricating of the periodicpivot tast. points and manually cycling the breaker) defeats the purpose ! i The staff stated that such preconditioning does not t confirm continued operability between tests nor does it provide infomation on the condition of the circuit breaker for trending purposes. The applicable licensee planned to revise its procedures before the next surveillance test to correct this situation. 1 In ASME Code Case OMN-1, " Alternative Rules for Preservice and Inservice i Testing of Certain Electric Motor Operated Valve Assemblies in LWR Power Plants (OM - Code - 1995 Edition; Subsection ISTC)," the ASME provides an alternative to the stroke-time testing requirements of the ON Code to assess the operational readiness of motor-operated valves (MOVs). The code case uses l the same language as the NRC regulations and ASME Code in stating that ' inservice testing is intended to assess the operational readiness of valves. i In implementing the code case, the licensee is required to detemine the capability of the MOV during inservice testing. The code case requires MOVs j to be cycled at least every refueling cycle with diagnostic testing conducted-on periodic intervals. - The code case allows grouping of MOVs with the I information obtained from individual MOV tests applied to other MOVs in the group. In Section 3.3, the code case specifically states that maintenance j activities, such as stem lubrication, shall not be conducted if they might
- invalidate the as-found condition for inservice testing. The performance of 1
j maintenance prior to testing would defeat the ability to determine any degradation in the operation of the tested M0V and to apply the test results j to other MOVs within the group. This code case is being endorsed (with certain limitations unrelated to preconditioning) for voluntary use by j licensees in a forthcoming generic letter. In summary, the performance of maintenance on a component to ensure its proper operation prior to conducting a test negates the validity of the test in assessing the operational readiness of the component. If the maintenance had i not been performed, the component may not have been capable of performing its j safety function. Clearly, the conduct of maintenance prevents the licensee i i from assessing if the component would perform as design, should it be called { upon. Further, important information on trending of operating parameters for evaluating degradation would not be available. ! EMEB Resnonse l In response to the specific questions from Region II: ! 1. The performance of maintenance that ensures the capability of a valve to satisfy the stroke-time test requirements of the ASME Code provides a false indication of the operational readiness of the valve. Therefore, a licensee activity to lubricate a valve prior to stroke-time testing 1 for the principal purpose of satisfying the test criteria at that i specific time would not be considered to be within the intent of the NRC i regulations under 10 CFR 50.55a or Appendix B to 10 CFR 50. It is j recognized that routine preventive maintenance, such as valve ! 3 i i i j
i
- lubrication, might coincide occasionally with IST program testing. In
- those cases, the effect of such maintenance needs to be evaluated to l l ensure that the ability to assess operational readiness of the valves I i
and to trend degradation in the valve performance are not adversely affected. i- 2. The NRC regulations, and ASME codes and standardsp require licensees to i establish IST programs to assess the operational readiness of certain ! valves and pumps. If a valve fails its stroke-time test, the licenses
- is required to declare the valve inoperable. Therefore, the stroke-time
- test is intended to demonstrate current operability. The licensee f evaluates past operability since the previous stroke-time test based in
- part on the most current test.results. The ASME Code prescribes l comparison of stroke-time test data to previous test data so that
- i. licensees may obtain an indication that the valve should remain operable ;
i until the next test. It is recognized that the stroke-time test is ! l limited in its effectiveness and, as a result, the ASME developed an !
- alternative IST approach for MOVs in ASME Code Case OMN-1.
I i b i i l t k i i i i i i i 4
FACSIMILE TRANSMITTAL U. S. NUCLEAR REGULATORY COMMISSION REGION II ATLANTA, GEORGIA , ENFORCEMENT AND INVESTIGATION COORDINATION STAFF To: @ M A I L- CES, MAL
SUBJECT:
1 E EL bl Ib (301+415-3431) C WF (301+415-2260) C OTHER DATE:JLA. I 51996 I, UC16 b [bb M l NO. OF PAGES [b + TRANSMITTAL SHEET FROM: BRUNO URYC, DIRECTOR, EICS l OFFICE: (404) 331-5505 FAX: (404) 331-0426 INTERNET: BXU@NRC. GOV TIME: ! SENT BY: / 1 l
4 0 l l l STAR 951048 I l l l l l l l t t l
07-15-1996 10:35AM St Lucie Residtnt Office 1 407 461 4622 P.03
' - W ST.LUCIE ACTION REPORT k IDENnFICATIONSECTION [f g,3 l- y, om l-
) woe nm.nonmeno 3 Veevses /eA-n ed srw.o.c."$Ew nuertption W i /2 - ooioi ts-A h %s B A M E ,' s/2.
% sseT - A towacunec es w-vnAzsm i h v_,s Cedo cr as. Tw <-m.avr TMr Tu
- __ C'" "
'PreerRLdirwO'T- 14At.T162
/1TE. TM$ L Tg\5Peg A QMsmeMMS~ inaMoualm %6h l~'crf
~.De . bub uanon i
r ea,ma ot. Twr V+1s i M rce Nor'~hnet.r Ttw-TUE-tr. kBluty O'e Tl4CE b.45 To ?trSS Trwr* $$-cfE' TtMI' T5T. opwmorN Oym o ! h - i _Os..NRC - Corresponderm _ . _ , 8, Audh Repon. i i _L_,o,-a- ASME XIB
~
- 4. Recommendeson to conect and 41. nifesponsible. _ _ 7 b% M - O $ / NRW
) . . -
W Head Sigpistur=//b Deen b
/1 Do a require soprovale close? NYes C N(
--i REVIEW / APPROVAL. .]
- 1. Assigned Depenmort. OPr/M<
5:;;ec p15T2r so..ucf y ,7.
/
- 2. Revtsws STAC ANil @ ISI@ Operabilky Assessment Required: JPN [ OPS O
- 3. NP70o O HPES C IHg Q TecMoel S@oomrrttee h Rettuired Q
- 4. Evoluedon clue try1./.,[ /M b10: / 7 Initials:
f I Exionded m: I . Intuals: h 5. Correcove measures completed by _ 1__
- 6. Isitemamodehoid?C yes No g .
c, ,,, ,2-w 0% vc!?r p Y YC 2 to,s Ptncf 9o eadee r nwr he.*eriec. s6smvre wr ADWrJ0 D TWA t'- TW r.T 4)o4 S 2bst f
~
W am f> 6 i15' ooyou requeo apprevw e ooat @a LJ No
- 1. Nb. 0.e, AP 0010721,'NRC Req. dred Hon Routhe Notincebons & Repons' O ve. O No AP ocoS782.' Punt Guide 2 Repor$ng EtMronmental Non-CorrpDenoes and 5%nincant Evems'
{ 2. EventType 18 - SP ocasias. Reporting of safeguards Evertts')
- 3. Security overt Cyes O No O FOP senature aos 7
(Gl.16&B.WPG) (Rev.1. Ales)
i 07-15-1996 10:36AM St Lucie Residsnt Offica 1 407 461 4622 P.04 i* , i ~-i ANALYSIS / WORK l STAR 8 9'S lO W, S OPS l
! DATE l lFWowforTeirves! Asemano. l ext e v .ene.
' DW j A. Accepublity#perate gyg -
- s. ergpnoseg secenas rer.aredE< of a non or ,enw<eem e.. g hem le h queadon and operstkrile of oesien.
COMP _ required. _, C. Ergineertrqi asemannoe needed for root c6use sleestmhedon.
- Tr1A
] D.E For esistrreistedquenly EQ owshanienle needed missedF. 10CFR21 " . poet leeue n Mi of nem is quesnoneben (as found conste Teceinloal C G.50.80leeus O H. ASMEXIleeue
! n any use wei, sue wn. cewe*ed answw v. ioso. ins. Meestuden reouired. Dans _ 1 / Mode 4
- m se,s e., o ,.s o. e., _ _ l Dispoeleense my verinedby ,
f i,wasmessenmosicausemenerieimonwwonasPwwensspense j ResponelePerson b#mo i FC - /-9 s~ 2CS Wns Uhurrco Ao Ecouunrw _.Lro /= 60/0 tM*A
- ,si - n. c_ w-_a .. -
G ;- Lv e a n re., pern D nr Akn As/t<i.A.)- i n. Tun Mso Aue LJ . u-G:l l h
- w Quingo VeNeenused Compleasd l
I Espected ! RequHic (,cu.Wo numter) Dans
- comeces Accone Assigned to cate
; SNO REF FRG - 95.w.,
- 1. PcR +.ndLa . /_,_f_,_ , O O u i__t_r a s l
f m, l Y _ _ l l k i S 1 1 __ { f f i l 4 JJ_ Q } j f
--(~~ ct.ossoursecnon ;
- 5. As .or- m e . m ne e ine egnens now .) #.L /[/M8/6, y/,, Asei,nedos,enmen.
l
- 2. % r a._- r h 1 , M ' G n,u ._x
- 3. ANilReview k M'^" r
! 4. m neview n/AM i MfdrIM i , , loc i s. occoncui== i .. ,ie no,e, unne.e,- Z_ E a u d . , ,,/i. A r ,.te,e m us,,,,e, co-' fo i e eene a=,een.<v and -e e.g w / 4 s% i ' (QW.16JC.WPG) i i
! 07-15-1996 10836AM St Lucie Residsnt Offic2 1 407 461 4622 P.05 l QI 5 PR/PSL 1 l
. Revision 62
{' May,1995 ! Page 83 of 96 l p MGURE 1 PROCEDURE CHANGE / REVIEW REQUEST l (Sheet 1 of 2) l PROCEDURE ThLE 8rrvp/kmWE [A 4 8 fb _
}
i
/. aoy0(2.f A __ Presort: Rev. No. .J V PROCEDURE NUMBER l
51.5 PCM or STAR /R62 ! 1 3333a D 1.1 Response to INPO, QA. or O 1,6 Procedurst isps,,,nrst /R62 l j for Recussi NRC Recuirernents 01.2 Cycle Specifir:/ documented Setpoint Revision. ['] 1.7 Tech. /R62 Man ! or Vendor Remon Q 1.3 Tech Spec. Rev4.lconsing Requirernent /R62 l 01.s Technicallyinconect
* (Ust Tech. Spec. Amendment No. below) i /R62
' O 1.4 Affects Plant Operabilty/Ava: lability D 1.9 Other nation: I4[kt l Include desenptionoand r e cesource e,e f, (i.e., PCM e. heSTlR one e), ifOr
>- g2' e Letail i l s huu s u e ev Ie iha tr e,'e a ~ s ra e i-95escs '
! t n hER
- I Attach a copy of the affected pages of the present revision. Changes should be legible 1 i
' RED ink directly on the affaced page. If extenske additions are recuired use additiona i sheets as necessary; clearfy indicate the proper placernent on the suf,W,ste page o revision. Highlighters, correction fluid or any other oblRefation material should not be 96ed
- 2. a. Is this change to a un:t specific procedure?
fYes _,,No - coi6fic,ri sa+2re f,,_Yes .,,,No
~
- b. 't yes, has a PCR for ths opposhe unt been sutetted?
11 no, explain No T.C. # (if applicable) /~ 9f .2_E
- c. Does this PCR incorporate a T.C.7 D es
- d. Does this PCR reference any enemical? ,Yes _No 1
!! yes. Chemical Control Supv. Review
- 3. Pefiodie Aewew_ (Checkif appik:able)
Check below enty if performing a review where no changes are necessary. f Q Review performed, no chang ts (FRG not required).
- 4. Manueste0 tnr.
da n N43/Ph // Phone J#MS - (print name): T- / A/ f (Signature): M Uh ' Date: 91 7- / T Datet Subcommitteed by: U @d- - / / Date: _ Dept. Head: i Prienty:(determined by Dept. Head) 01 02 03 04 _.) _ (if applicable) s oes Recutred by / DATE cocT i
.it?
ITM ]
- -. __ - - . 7..
P:ge 32 ~ 238 .
, , ST.Lb . UNIT 1 ?
'9 ADMINISTRATIVE PROCEDURE NO. 1-0010125A, REVISION 39 SURVEILLANCE DATA SHEETS J DATA SHEET #8A VALVE CYCLE YEST - NON-CHECK VALVES PJ (Page 5 of 9)
'9
- s Note: S in required stroke time column im5 cates ESFAS valve.
-s O-l Saggisct. .4 ogy 8teke T6anchecSon Fat Posisen gp yes,,
Exetdse Essar Maienune Enter Fed Restored fDelike Vahe Actual Roghed Acked Reqated I.V. Regiered Test Vafve No. D@ (Wilds) 11sne Time QC Poolport Pestion (Iremis) Atter Test Moesed Resnsets t FSE-27-s* SengesIrdo AH, Analyrer Oosed B FSE-27-e* SeniWe tree 9 H, Anadyrer Capsed B 2 O MA NA fSE-27-10' Serigle Isoin 8 H, Analyear , caosed B FSE-271l* Sersive hora A H. Ansfreer closed a
?.
- FCV451E* S1T Sernple Line toolston 2 C FC Closed B
- FCV 4 11F* SIT Senple unelectaflon 2 C FC b,Y AloT Closed B o -
g ga s T 3 g Ensure t - -,7;; rt...._; FCV471A Corsahrner18 Spray Hdr A O FO Dosed 8 ( prior so seseeihg yEVs(M5 W n a j ' MV47 3A A Cemaahreent Spesy lael .120 C WA NA Open WA \ 2s o NA MA
- h
. en se471A ceuese kvecika 2 C FC CIooed B
*FeetAcang Vafve b V-07145 MA NA C WA NA odied WA Tested lay OP 1-0420050 m, L .. i s, . . . . . . . . .
- m. ;
(g '
;. .3 ...
.i.# ,' 9 :N*O)N i
l 07-15-1996 10:36A1 St Luc 1e Res1 dint OH1ea ; 407 461 4622 P.08
'
- Ol 5 PR/PSL 1 l .
Revision 62
' May,1995 l Page 83 of 96 FIGURE 1 PROCEDURE CHANGE / REVIEW REQUEST l (Sheet 1 cf 2) i l PROCEDURE TITLE SvN# i((aan 84 /* MFNJ i
2_- 9p /S / 2.fA Present Rev. No. #f 3 -- PROCEDURE NUMBER l g 1.5 PCM or STAR /R6 1 1. Reason 01.1 Response to INPO, QA, or /R6 NRC Requirements D 1.6 ProceduralImprovement for Recuest l' O 1.2 Cycle Spect'ic/ documented Setpoint Revisicn. O 1.7 Tech. Manual Req or Vendor Revision /R6 C 1.3 Tech Spec. Rev/L! censing Requirement l 01.s Technicallyineoneet /R6 i (Ust Tecn. Spec. Amenoment No. becw) O 1.9 Other /RE O 1.4 Affects Plant Operability / Availability Include derpription and source (i.e., PC/M #. SJAR #), if her give detailed exp l i sin (d mf be o t e ro n d fren e (A0 'BSor to A ur ve r (fa-e e il 37v l ~ 9 f o f f. % j I IEli. Attach a copy of the affected pages of the present revis!cn. Changes should be legible in l RED ink directly on the affected page. If extensive additions are required use additional l sheets as necessary; clearty in@cate tne proper placement on the appropriate page of the oki j j ttmSton. Highlighters, correction fluid or any other obliteration mater {al should not be used. I s
- 2. a. is this change to a unft specific procedure? Af,,Yes _No commen proescure IYes No j
- b. If yes, has a FCR for the opposite unit been submitted?
1 If no explain -_
- c. Does this PCR incorporate a T.C.? . pes ,,,,,,No T.C. e (if applicable) 1- W-/ *7 3 l .aggo
- d. Does this PCR reference any chemical? .,,,,.Yes l
i If yes, Chemical Contro! Supv. Review i
- 3. Periodic Review (Check if applicable)
Check below only if performing a review where no changes are necessary. ) l 0 Review performed, no enange3 (FRG not required). 1 4 Reouested.gy: (pnnt name): det k4 Fem Phone J 88 [ (Signature): f-f7% % f.Oda,. Date: 2,,./ ,,/,, _/ T Shimmed by: WM --
~
Date: 9/ 2- / 95 l / Dept. Head: Date: / { Priorey: (determined by Dept. Head) O 1 02 O3 C4 l _ (if applicable) Required by / / s_.,, ops 4 DATE i DoCT Dom } BYS
- CCW
{ rN r
-, rcr,r.-
l
.._a . -4 4 ...A.
9 4 8 i i STAR 951063
1 07-15-1996 10:40AM St Lucie Resident Offiee . 1 407 461 4622 P.11 STAR) ~ ~ 48. - s rA m e . A h t> 2~ ' '..g ' r @p. I _ . . - _ _ _ _ _ _ . , H marviarmAisure amisust ' Dese y 1 Y i 9 C . m - h . f o n. O 07.5" __ q 60, ,
' l .. (/ ' N.?.'k . '. l4. 6h .
i b,a & %ar (2,,r / .G/o.1, y_L s., prrwnan '7hy .y,,: g,pp. . %f, - h} rew-are - n, n,- o wm s.snt Mar Maw ,,,;,, -
.w l A.= Aan Gann, wr br Manua ~ .
s . .,. r: l Ra % >olerar Pr> >a nn s rv besu . L = Gear .... . . . .. ,,... ., 1 Rs brain Caa. mum m< dn h uo m w f' IP A * ' '
. ~,
l Gre ae .Crurina ? . .. ... ..y i. l
' c. .A7 .
gs, ppm Ossespondenes 9. AukReport. Opereur&48;Y [D.nel:!-[$8; . T-R'8'""888 Ormuhgf.personnelabsammen,shQ ,u
. .. ;;t
'n..P.,g;... ;c, ,3
- a . . . . . .,.4.
. ,: 1. inc*Ji to.
i
, ,. s,..
.. %. m . . tw. , . ..... .- ,.
.?.
1
', : .>. : .. '. : ' ; r V."..*J. '.' . 99. 'p. " .. x
.y
,::a..,.ggeo
- honens . .- . ..
., .:. x : '
2,.1
- 1. Wege any steps alento erAle=* O v=e O No -
. .' .', ~". . 3;-
- 2. W m M W m M M c. .
'".' . y. .A, g
. . . , . .I
'- ' 'N. .';.: '
i s. auspeasdemmeeremndemn alyneen. . . . . . . ,.. , .s . .u a,wwrp. mar,:gaca 9., wen l
~~ .togenestandespuvusetresperatis. biwt'r#' ~ dun' M@MVMWMk
- 4. .'Et aenunme @ 'Aum L An A' as TM i s W=>1'or . .',.W L'" :' MC j l --
, ,A
.e .. . e. .: .s. e . y- m .:g,p m mli.
DamerenenHead-
- \ 1 Dets S 3 M 1 b you Nis'eN s'~5' s C
. .. . . . . . . ?.
( 5. AsegnedDeperseers. NN-sum. " - .. -s5BL l 7 5}/ '"" - T= n- ^"" '- ' y' {Uh Q g r..'i.;.g .j
.. . .. . 74
- s. m.= STA O AmuO =0 b *** l enesneyAi; enannapeee
- tian O cre !- '.T 78esudeal alassmennesse.M. R.egend Q.. !. G. .ff-k
' 1
! 3. MP700 C DW'E3 C . ,9,4E .
.. y
- 4. E,etunden da by M f If f 9 T. Im f -1 Ingels: f, ' .s . ,. . . - :,/0, .$.
.c1,,J.
- 5. Genesevernessnessempestedty_lif I fM Essunsedter f *'t innimis: ' ' i' .'.U, ; ;. .. : !:@- p ,
' 8. Is ham a mode 4 ..Yes C No h Ih .> l. h,h,
,.. ', k NEfrb . *fe c.DM P t.rTF f.Eyi F u.) .(M.: 0 K. v o' (1 '2.. SvMtY.(Ab ..'
Conenents: .
. . . . . . . . , 8.,
. 'eM ;
. .,y
, - on w -, oe-res e.,r is o s'ta,17l ts'ga::f.; ..
. N ' Y P ' Yes1 0 'Hui) E 1 b $4., APINP10FR1,ifl0Requbed NonMauene Nutlastens & Reports' ,
i AP 5057M, " Plan thods te Repute Erwbuensrael Nencengduisse and SW Bau l
arcoostas.'nspreisofsangeresy . ,; . 49, . ggpf, .
- s. 71 .
=. d: . A .e:: .,;,..,,.;gp,x/i.&
.r. . . .e,e . . W ... . ,.
F
/# Yes No O . POP . ' ., , Md.tn ,. _ _ : . :c, um, % ,g 3.. Securer suert -
- h. __ _
. IS. d .5 YbY , h
07-15-1996 10:41AM St Lucie ResidInt OHic2 1 407 461 4622 P.12 n e - y gg , m j I Inter-Offloe correspondence i l l j l
- i. ,
,m..
o.te: October 5,1995. , . l l To: PaulPulford l jn, Ops Test j p, : JonHallem Dewir=t: , aubioet: STAR 95100 Response :T" y.y , l . .. . l I have reviewed the test and swveillance procedums pertaining to the laservice tes pumps and valves for both Units 1 and 2. I found no further instances where prevent
,sl '
rnaintenance h specified by the procedure to be pJ-.4 prior a the test or surwillance. .;]:-. 7. lj , The plant does routinely perform PMs prior to Mnw quarterly (.; ) as a matter of conveniences since a surveDiance run is required following the PWI.vDy > .L I scheduling the PM work to be performed prior t(tlie'acheduled surveillance ~tlie M,ofq%g surwillances performed is reduced. This is desirable because this limits the nisber o i demands placed on the pumps, the amount of opereenr manpower needed to swim,esets, , . . , ! and reduces the unavailabilty for pumps which are taken out of service to perfbran the' e surveillance. Attached is a listing of the PMs performed prior to scheduled surveillances. . .. '- . l ' ! These PMs are intwo major categories; pumps and fans, and valves and AFW Terry M. I have reviewed these PMs with the applicable SCE and Predictive Maintenance Engineers and have collectively come to the following two conclusions. . I For the first category, the PMs are for pump oil change out, coupling lubrication and hn . I lubrication. These are considered to have a minor,if any, impact on the performanan of the pumps and fans during the surveillance . These PMs are performed less fr.g.c.s:ly tha quarterly surveillances with no indication that the pim m or lack of the activities has influenced any surveillance. Also, some of the components are run during normal plant operations, and problems with Charging pump accumulator pressure and otner pumps a fans are detected by Operations during normal oh.4=i of the +s7-:+'+. Therefore this first category of PMs should continue to be performed prior to sobeduled surveillances. The PMs gifwod on FCV 071A, FCV-071B, and the AFW Tr .". Turbine, a' nd Governor valves may have an impact on the performance of these components. .The tests performed on the Unit 2 MFIVs have no effect of the safety related fonction ofihe ' M surveillance. This category of PMs with the exception of the MFIVs abould be reacheduled . ikom just prior te se p fe;mance of the surveillances associated withthese components.'
- a. -
<. 'y .. ,g
- n ..- ..i.}p,v:t (:,}.y.
," . ..[,' I , {
e5 TUTAL P.12
9 e e AP-1-0010125A l I
. _ _ . _ . _ _ _ . _ . _ _ _ _ _ ~ . _ _. ___ _ _ - . . . Page 4108 236 -
- I ST.LU- UNIT 1 \
ADMINISTRATIVE PROCEDURE NO. 1-0010125A, REVISION 39 . )l SURVEILIANCE DATA SHEETS 3 y DATA SHEET #8B ,. VALVE CYCLE TEST - NON-CHECK VALVES _l (PaDe 5 of 10) 9: Q, Note: ' S in required stroke time colwnn indicates ESFAS valve. 2 , i I Sesstect-l W ! cdy Strese Mocton Feu m sy.ne. vs. Esosdse Etitor DAestruen . Enter Fat Restoest Positten E ,. ve#re Acives ne,med Acaw Regees tv. ne, dred Test 'l ! Ve% No. DestfEp k . Tune Time OC Pospen Ator Tesa Remarks * (tartansl Peelsen (Inslate) 14eshed V43920 SIT Odet orev.b yci sera fefA O M MA Qosos ferA g! ISEM 41 teop 10t Changing leel 5 O FO Open 8 (Data Sheet MB) et semo time. hs -2m {.. 5 c NIA MA Conduct east of V 2432 b
** er . teop tA2 0===w " '*a "
s o co m sei.ei nssi si .es e. g: t O '
" '" U V-2504 IWff toChargirePumps N/A NA Closed
- i 12 '
c > es pee pso, "s. cycnn2 ; v,esor " " * ' '
- s c em tea open wA i S
V4554 vemme Oas Osnttool C FC open B 3 ve mmmw c m % a g* 2 gat t v474r 3 c rc cieeed a
- res Acene veh. 6) .
." I rever.is C"""*"'* 88"*r H&9 s
3
, ,o ,,, , gTE ,en mru-T
( palemed pdw k stdhg. mot k,
#d pgyj,g g a coniseenene ' " /
uver-as m c evA evA La*** wA 88FM 1 Open 2 REV 6 , SE47-19 Casesc trisecon cleeed B 2
- Fast Ach0 V88ve ar- tec -, - - - c - ,
,. g 1.E,e., ,, o,. , _ .
e, ij W w w.w e..h.,
-h3 k. g;
4 ..u.4 43 s_Am.___m_ dA-_. .a.# .a+ w s- A u .-e a A2 O 9 0 AP-2-0010125A
- Page 52 e' 254 *- "
~
t ST. LUCIE UNIT 2 .. , g ADMINISTF1ATIVE PROCEDURE NO. 2-0010125A, REVISION 43 - SURVEILLANCE DATA SHEETS g DATA SHEET #8B ~h ' VALVE CYCE TEST - NON CHECK VALVES l, {Page 11 of 13) @' Note: S in regtAred stroke time column indicates ESFAS valve. Soestact- to , eu8r SI'esi. Teneme, sedan Fa. Poes.n syste,,, y g., , Essedse Es.or handman Enter Fall Restored PosWon System Vehe Achsel ReqtJeud Actset RegrArad LV. f4gded Test {i 0 f Veno leo. Descripson (Mitials) Tene Thee (We Poeman Poeginn (intlefs) After Test heathed Remedes I esTiat jg1
- 1. Hove 14C ut L.ed #2 on en ;
( p-S5 O FU TB S49 m cettnet ESC-SS. E, , SE4748 20 Hyeate Pwvy Dhch Closed S 2 Cyde SE 87-38. 2 43 l' S C WA NR
-Qs2 en N <r -Q -
E C8 "* 8 o ro [! g eCverse c.ed a cm d af Ea""* .% ",cy .,.N. Wa r'#' , g ==
==
o-a*==* s as a - n 8 c c rc g o, s qj
\biJ NdT ;
rev m cw S c rc op a E* 57 # i rev m -w s c ,o o,,,, , v;*" g;
-~ -- ;
. c ,o _ . 3.
-~ -- ,
; c ro o,e,, ,
g! t,-
== o n -- ; o Po o,,s., . g -
r p g 4 3u , g $*j -. g! sg n=, m. . . ..,... ,
I 1 GtR Fax 8404-331-6471 4
' ** Transmit Conf. Report **
Jul 15 '62 12:08
-> 8-301-415-3431 GtR I
No. 0003 i 3' i Mode KRl'R. Time d'30' Pages 14 Page(s) l t Result- 0K i J 9 ,1 .) )- l 2 , 1 1 . . j I _ l i i l' l J 9
5 1 e ^ ENFORCEMENT ACTION WORKSHEET a
! INADEQUATE SAFETY EVALUATION PROGRAN PREPARED BY: John W. York DATE: July 7, 1996 NOTE: The Branch Chief of the responsible Division is responsible for preparation of this EAW and its distribution to attendees prior to an Enforcement Panet. The Section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e-mail (ENF.GRP, CFE, 4
OEMAIL, JXL, JRG, SHL, LFD; appropriate R!l DRP, DRS; appropriate NRR, NMSS). A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is required. Copies of applicable Technical Specifications or license conditions cited in the Notice or other l reference material needed tyvaluate the proposed enforcement action are required to be enclosed. This Notice has been reviewed by the Branch Chief o Division Director and each violation includes the appropriate level f cificity as to how and when the requirement was violated.
" SigriatWe Facility: St. Lucie Unit (s): I and 2 Docket Nos: 50-335, 389 License Nos: DPR-67. NPF-16 -
Inspection Report No: 96-?? Inspection Dates: ?? Lead Inspector: John York
- 1. Brief Summary of Inspection Findings: (Always include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then, either summarize the inspection findings in this section or reference and attach sections of the inspection report.
Inspectors are encouraged to utilize the Noncomplianco information Checklist provided in Enclosure 4 to ensure that the information gathered to support the violation is complete.] Four examples were identified for violation of 50.59 requirements: Example 1-The licensee concluded using PRA techniques that closing a manual valve (because of a leak in the transfer line) to the day tank of D
, ,., ; o the EDG would increase the probability of a failure of the EDG by 6 %.
However, in considering 50.59 criteria, the licensee concluded no . increase in probability of component failure and therefore no Unreviewed Safety Question was identified. hamole 2-An enclosure was fabricated in a safety related area without y performing a safety evaluation (50.59), i.e. no seismic analysis, etc. Example 3-Fire protection plan requires that two 2300 gpm fire pumps be ', operable at all times. During a refueling outage, electrical - configuration was such that one of the pumps was removed from service and a smaller (750 gpm) pump was installed. This violated the fire q l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE }\ WITHOUT THE APPROVAL OF THE DIRECTOR, OE
- . . . . . - - - - . - . . - . . . . . _ - . - - - - - . - . . - - _ . ~ . - _ _ . _ . ~ . - - . - - - . -
l . t --t 4 . ENFoRCEMEIrf ACTION ; wnernment (. I
- j. protection configuration in the UFSAR and requires a 50.59 evaluation. -
! Example 4-The licensee changed the refueling hoist interrupt setpoints I with only an engineering analysis. Since the set points were outside #y 2 the UFSAR values a 50.59 safety analysis was required. See attached IR' feeder and proposed NOV for details. ! 2. Analysis of Root cause: , ? . i ! Attention to detail, inadequate review of UFSAR in the 50.59 process.
- 3. Basis for Severity Level (Safety Significance): (include exemple from the
- supplements, aggregation, repetitiveness, willfulness, etc.)
i . l L .The number of examples indicate a programatic breakdown and lack of. ' i management oversight of 50.59 such that a safety concern is present. - regarding compliance with the requirements of 50.59. Also, a condition ' n existed where a required license amendment was not sought, i.e., an USQ ! -existed and the condition was not sent to the NRC for review. , 1 i [ 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections? [by EA#, Supplement, and identification date.) y None identified? ! ! 5. Identification credit? Depends on the example. ! l [ Item 1-Inspectors identified that the licensee did not' identify an Unreviewed Safety Question. I l (No)
- Item 2-In response to an alarm and related maintenance,'the licensee
!. identified that an enclosure in a cable spread room (safety related l area) did' not have a safety analysis. (No) i Item 3-Inspectors identified and questioned a different size fire pump. l (No) l Item 4-Licensee STA and safety commmittee identified that a 50.59 safety !. analysis had not been performed. (Yes) p Enter date Licensee was aware of issues requiring corrective action: [5/96] i ! 6. Corrective Action Credit? ! Brief summary of corrective actions: [ In response to the issues, the licensee adopted corrective actions which i' included: A NL Operator was assigned to operate the fuel valve for the EDG and a j procedure was changed to indicate the compensatory action. In the other j cases the required 50.59 safety analyses have been performed, UFSARs are a PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE } WITHOUT THE APPHOVAL OF THE DIRECTOR, OE p
- , - . . - - - .. :, - - , . . -.,n..
1
+
1 O ENFoRCEMEIrr ACTION woaxsaEET 6 being changed, and root cause determinations were initiated. j Explain application of corrective action credit: Corrective action appears to be of appropriate scope. j
. 7. Candidate For Discretion? Yes Explain basis for discretion consideration:
Licensee's performance has been considered superior in the past.
- 8. Is A Predecisional Enforcement Conference Necessary? Yes Why:
To determine adekuacy of licensee's proposed long-term corrective actions regarding the 50.59 safety analysis program. If yes, should OE.or OGC attend? (Enter Yes or No]: ) Should conference be closed? [ Enter Yes or No]: 1
- 9. Non-Routine Issues / Additional Information:
i This issue should be discussed during a PEC along sith the issues panelled the week of July 1. 1 l 1 I i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
.. . -. . . _ . . . = . .. _ . ~ . . - . - . . - . . . . . - - - . _ . . . . - _ . . . . . - -
ENFORCEMENT ACTION i woRxsuRET
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued
- [EICS to provide] (if inconsistent, include:1 i
- Basis for Inconsistency With Previously Issued Actions (Guidance) i
- 11. Reguistory Message:
Control must be maintained over the screening and performance of safety analyses (10 CFR 50.59).
- 12. Recomended Enforcement Action:
SL III-Under current NUREG 1600 examples I.C.5 and I.C.7 under draft examples I.C.10,.und I.C.11.
- 13. This case Meets the criteria for a Delegated Case. [EICS - Enter Yes or Nol l
- 14. Should This Action Bo Sent to OE For Full Review? [EICS - Enter Yes or Nol If yes why:
- 15. Regional Counsel Review [EICS to obtaini No Legal Objection Dated: -
- 16. Exempt from Timeliness: [EICS) t Basis for Exemption:
Enforcement Coordinator: DATE: l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
ENFORCEMENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION ]. O Problems categorized at Severity Level I or II. O Case involves overexposure or release of radiological material in excess of NRC requirements. O case involves particularly poor licensee performance. O Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with OI regarding the case, whether or not the matter has been formally referred to 01, . and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address , the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included. ' I O Current violatioh is directly repetitive of an earlier violation. O Excessive duration of a problem resulted in a substantial increase in risk. O Licensee made a conscious decision to be in noncompliance in order to , obtain an economic benefit. O Cases involves the loss of a source. (Note whether the licensee self-
! identified and reported the loss to the NRC.) i O Licensee's sustained performance has been particularly good.
O Discretion should be exercised by escalating or mitigating to ensure I that the proposed civil penalty reflects the NRC's concern regarding the violation at issue and that it conveys the appropriate message to the 4 licensee. Explain. l j PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
__ _ _ . _ _ . _ _ . . . ~. _ ____ _ _ . _ l l . Enclosure 3 , REFERENCE DOCUMENT CHECKLIST i l i [] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: [] Licensee reports: [] Applicable Tech Specs along with bases: [] Applicable license conditions l l [] Applicable licep'see procedures or extracts [] Copy of discrepant licensee documentation referred to in citations such j as NCR, inspection record, or test results [] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability ; i [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections i [] Other miscellaneous documents (List): i 1 1 a 4 l PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Safety Evaluations 10 CFR 50.59 Issues a The inspectors reviewed and evaluated other 10 CFR 50.59 safety-screenings and safety evaluations but the following four were identified as having problems. ,
~
i A. Safety Evaluation for Closing Manual Valve to EDG Fuel Supply ; The inspector reviewed the safety evaluation JPN-PSL-SENS-95-013, which was prepared to allow operation with a manual isolation : valve closed in the 2B EDG fuel oil (FO) line from the DOST to the - day tanks. The configuration was proposed when a leak was determined to exist in the underground line between the two tanks. The action was designed to minimize the amount of F0 released to i the environment until the' leak could be identified and corrected. 2 As a compensatory measure, the licensee proposed' dedicating an NLO ! to the task of opening the closed valve in the event of an EDG , start. The licensee calculated that the EDG day tanks contained ; enough F0 to allow 126 minutes of EDG operation at full load , before a transfer of F0 was required. The licensee then specified i that the NLO would be required to open the valve within 20 minutes ; of an EDG start. Procedures were revised to include direction to open the valve on an EDG start, and administrative controls were ! put in place to ensure that-the NLO would not be required to ; perform any other immediate response duties. Additionally, the licensee performed a response time test, placing the. operator at the G-2 warehouse (as far away from the EDG as he could credibly be in the protected area) and requiring the NLO to proceed to the 'j valve and open it. The NLO performed this task in approximately j seven minutes. In considering the issue, the licensee employed PRA techniques to estimate the increase in the risk of the loss of the 2B3 bus due to a failure of either the operator to open the valve or a failure of the valve to be able to be opened. The licensee concluded that the increase in probability was approximately 6 percent. However, I in considering 10 CFR 50.59 criteria, the licensee concluded that ; no increase in the probability of failure of a component important to safety was created by the proposed action. The inspector questioned the licensee on this issue. The licensee explained that.a deterministic conclusion of no increased probability was reached when the existence of procedural guidance and heightened awareness was balanced against the approximate 6 percent increase in failure probability presented by the two new failure modes. In the context of regulatory compliance, the inspector noted that 10 CFR 50.59 was written in-terms of absolute increases in the probabilities of failure represented by a proposed change. The inspector continued to question whether 10 CFR 50.59 criteria could ever be satisfied when new failure modes are imposed on a previously reviewed system (i.e whether added risk, once qualitatively established, could be completely mitigated). The inspector concluded that insufficient guidance existed from a 1 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE i WITHOUT THE APPROVAL OF THE DIRECTOR, OE j i
1 e l~ regulatory perspective to take immediate issue with the licensee's ! [ rationale. Further, the inspector concluded that the licensee had 4 4 taken prudent measures to ensure the continued operability of the j . 2B EDG while minimizing.the F0 leak's effect on the environment. ]. The inspector referred the question to NRR for resolution. 1 After consideration of the issue, the NRC determined that the j' actions taken by the licensee in this instance introduced.two new .
- failure modes'to the EDG system
- failure of-the operator to unisolate the fuel oil line and failure of the manual isolation
. i L valve to cycle. As a result, the NRC has concluded that the. ;
- licensee's actions necessarily increased the probability of a !
, failure of a component.important to safety and, as such, I
- represented an Unreviewed Safety Question, as. defined in 10 CFR l 50.59. . Consequently, this action is identified as a' violation j (VIO-96 XX-ZZ, " Failure to Satisfy Requirements of 10 CFR 50.59"). ;
B. Safety Evaluation for CEDMCS Enclosure i < } On June 4,'1996, a control room annunciator indicated that an i undervoltage condition' existed on the Control Element Drive l Mechanism Control System (CEDMCS). Operations responded to the a CEDMCS equipment and noted that the CEDMCS enclosure was 1 approximately-11 degrees warmer than normal. This enclosure is I
- located-in the cable' spreading room on the 43 foot elevation of 2
the reactor auxiliary building. , l Following this event, an STA In-House Event Report and Condition a j Reports 96-1238, 96-1245 and'96-1325 were issued. Some of the i following items with appropriate plant corrective action tracking number were identified by these reports.: CEDMCS enclosure and air conditioning units did not appear on the plant's controlled drawings.
- (STAR 951320)'
CEDMCS enclosure air conditioning units were not seismic
- qualified. ' Final design was in. process to provide seismic restraints for the air condition units. (PM 96-06-208)
As part of the action for Condition Report 96-1325,' a 10 CFR 50.59 i safety evaluation was performed on the CEDMCS enclosure. The ) evaluation found that this air conditioned enclosure was erected i in the early 1980's during the pre-operational testing phase. J This testing found that the CEDMCS enclosure required an air ' conditioned environment to' prevent overheating of the four CEDMCS l cabinets. The licensee's review determined that the design of the j enclosure was acceptable, except that the air conditioning units and one air conditioning duct presented a hazard to safety relate.d I equipment in a seismic event. Therefore, seismic supports and i restraints were provided for the air conditioning units and duct ; prior to the unit's restart on June 13. The inspector reviewed the 10 CFR 50.59 evaluation provided for the design 'and installation of the seismic restraints and PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
justification of the installation of the CEDMCS enclosure. This air conditioned enclosure was erected during the pre-operational .s ~ test phase in the early 1980's to provide cooling for the CEA system. However, a 10 CFR 50.59 review was apparently not performed when the enclosure was originally erected. The CEDMCS i was described in the UFSAR but the cooling system and enclosure 4 for.the CEDMCS were not described in the UFSAR. This was j: identified as another example of-URI 50-335,389/96-04-09, i " Failure to Update UFSAR". The failure to perform an evaluation as required by 10 CFR 50.59 i prior to making a change to the plant as described by the UFSAR is j . identified as a second example of Violation 50-389/96-XX-YY, 1 " Failure to-Satisfy the Requirements of 10 CFR 50.59." Also, the
- failure of the licensee to impose design control measures on the i fabrication of the CEDMCS room and its air conditioning system is l an additional- example of VIO 96-XX-XX, " Failure to Adequately l Manage Configuration Control".
'C. SafetyE[a'luationforInoperableFirePump j During the Spring 1996 Unit-1 refueling outage, one of the two
. Unit'l EDGs had been placed out of service to perform maintenance i and modification work activities. Only one EDG was in service to
- j. provide power in the event of a loss of power event. To prevent a i possible overload on the single EDG unit, a number of breakers to
- various components-were opened and the units 480V electrical ,
l busses were crosstied in accordance with OP l-0910024, Rev 6, i "Crosstying/ Removal of 480V Buses." One of the components removed j from service was Fire Pump 1B. The breaker to this fire pump was d opened on May 21, and this pump was removed from service and remained out of service on June 8, the end of this inspection j period. AP 1800022, Rev 16, " Fire Protection Plan," Appendix A, Sections j 2.2 and 2.3 required two fire pumps rated at a capacity of 2300 1
- ' gpm to be operable at all times. Appendix A Section 4.1.A stated l l that with one of the two fire pumps inoperable, restore the !
l inoperable equipment to service within seven days or provide an j ! alternate backup pump within the next 30 days. ; ! Fire Pump 1B had been out of service for 18 days. The ! compensatory measure established for this pump being out of ; , service was the installation of a_ portable gasoline engine drive l pump rated at 750 gpm. This pump had been connected to take ' i suction from the fire protection water storage tank for Fire Pump l 1A. This alternate pump was not of the same capacity as one of
- the two required pumps and a justification was not provided to
! demonstrate that this pump was of adequate capacity to meet the ,
- maximum fire flow requirement for the safety related areas of the
- plant. The licensee initiated a CR to review this item.
y The licensee informed the inspector that the out of service pump could be restored to operability by restoring the existing open j breaker to the closed position. Also, the 30 day time to provide i PROQ'O ENFORCEMENT ACTION . NOT FOR PUBLIC DISCLOSURE M THOUT THE APPROVAL OF THE DIRECTOR. OE
'~
an alternate backup pump had not been exceeded. This met the requirements of AP 1800022 for one pump being inoperable. s Resolution of the Condition Report (CR 96-1356) indicated that the installation of the portable fire pump as the compensatory measure with one of the permanently installed fire pumps out of service ) violated the fire protection configuration as described in the ' UFSAR. An engineering evaluation should have been prepared to justify and document the temporary configuration. This is a third example of Violation 50-335, 389/96-XX-YY, " Failure to Satisfy the Requirements of 10 CFR 50.59". D. Safety Evaluation for Refueling Equipment Set Points Condition Report (CR) no.96-812 was issued by the licensee on the ! safety evaluation number SEFJ-96-020, it Lucie Unit 1 Refueling ! Equipment Underload and Overload Settings. The report stated that I an engineering evaluation had bear, we.tten to modify the overload and under] bad setpoints described in he FSAR without performing a 50.59 safety analysis / evaluation. These overload and underload load cell setpoints provide a margin to account for resistance l encountered while lifting or lowering fuel assemblies and prevent exceeding the fuel assembly and refueling equipment design loads. The licensee had obtained information from the vendor for use in this Unit I refueling outage which would allow an increase in hoist interrupt from 10 percent to 200 pounds (approximately 18 percent for regular fuel assemblies). The original engineering analysis did not take into account that these changes in setpoint values would affect the FSAR and thus the deviation report (CR) was written. St. Lucie Quality Instruction (QI) 2.0, Engineering Evaluations, Rev. I dated January 31, 1996 provides general requirements and guidance for the development and processing of engineering evaluations. This procedure references QI 2.1, 10 CFR 50.59 . Screening / Evaluation, Rev. I dated March 30, 1996, which states in part that the screening process is designed to determine whether the activity requires a complete 10 CFR 50.59 by asking a series of four questions. One question, "Does the change represent a change to procedures as described in the SAR?" should have been answered yes in the case of the original engineering analysis. The procedure also states that, " A positive response to any of the first four ...... questions requires a 10 CFR 50.59 evaluation". The Facility Review Group (FRG), the site safety committee noted that a safety evaluation was not present with the requested procedure change and returned the procedure to the engineering group for correction and the CR was written to identify the problem. This violation of procedure which required a safety evaluation (50.59) be performed is a fourth example of Violation 96-XX-YY,
" Failure to Satisfy the Requirements of 10 CFR 50.59".
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLtd DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
a .
- 10 CFR 50.59, " Changes, Tests and Experiments," (a)(1) stated, in part,
. that a licensee'may make changes in the facility as described in the i ; safety analysis report without prior Commission approval, unless the :
- -proposed change involves an unreviewed safety question. 10 CFR 50.59 (a)(2) stated, in part, that a proposed change shall be deemed to involve an unreviewed safety question if the probability of occurrence-P of a malfunction of equipment important to safety previously evaluated
- i. in the safety. analysis report may be increased. (b)(1) stated, in part, i the licensee shall maintain records of changes in the facility to the a extent that these changes constitute changes in the facility as '
I described in the safety analysis report or to the extent that they i i constitute changes in procedures as described in the safety analysis { report. These records must include a written safety evaluation which ! provides the bases for. the determination that the change does not > j involve an unreviewed safety question. k The following four examples of a violation of these requirement were identified. Example 1-Cont /a'ryto.theabove,inJuly,1995,thelicenseemadea j change to the facility which involved an unreviewed safety question when the 2B Emergency Diesel Generator fuel oil line from the fuel oil tank 4 to the day tank was manually isolated to secure a through-wall fuel oil leak. In taking the action, the licensee introduced two failure modes ! into the 2B Emergency Diesel Generator (operator failure to open a { manual isolation valve during a valid demand and the failure of a manual isolation valve to change state during an attempted opening) which-necessarily increased the probability of occurrence of a malfunction of I the Emergency Diesel Generator above that previously evaluated in the safety evaluation report. ; Example 2-Contrary to the above, the licensee erected an enclosure around the Control-. Element Drive Mechanism Control System during some period around 1984 without performing a safety evaluation. This non-safety related structure was erected in a safety related cable spread room. Example 3-Contrary to the above, during the 1996 Unit I refueling outage with only one operable emergency diesel generator in service, the licensee removed one of the two 2,500 gpm fire pumps from service and installed a temporary 750 gpm fire pump arranged to take suction from fire protection water tank 1B and discharge into the fire protection water system via fire hydrant No. 12 without performing the required safety evaluatien. The fire protection water supply system is shared by Units 1 and 2 and is described in UFSAR Appendix 9.5A, Section 3.0. Example 4-Contrary to the above, the licensee used an engineering evaluation to change the set points and procedures described in the FSAR for operating the fuel hoist without performing a 10 CFR 50.59 safety analysis / evaluation. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
-[ tc . k. L@5 i.
ESCALATED ENFORCEMENT ! PANEL QUESTIONNAIRE INFORMATION RE0'JIRED TO BE AVAILABLE FOR ENFORCEMENT PRE-PANEL : 4 PREPARED BY:'S. A. Elrod. . NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This information will be used by EICS to prepare the enforcement letter and Notice, as well as the transmittal memo to the Office of Enforcement explaining and . justifying the Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie Unit (s): 1 Docket Nos: 50-389 License Nos: NPF-16 ^ 7 T - '
e 7 7 _, Inspection Dates: > 3-7 30!94 i LeadInspect(or: S. A. Elrod A - . -
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate") which includes the recommended severity level for the ' violation is enclosed. 1 [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. [X] Copies of applicable Technical Specifications or license conditions cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best .
j fits the violation (s) (e.g., Supplement I.C.2) } I.D.1
- 4. What is the apparent root cause of the violation or problem?
i
.- The primary root cause appears to be a failure to recoanize the need to satisfy both the intent and the word of Technical Specification (TS)
Action Statements (ass). Additionall y, a failure in licensed operator trainino contributed to confusion in interpretino the TS AS.
- - THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE WRC WITHOUT THE I APPROVAL OF THE REGIONAL ADMINISTRATOR O
t l [ ,
'2 '
p ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE
- i. l l S. State the message that should be given to the licensee (and industry) i through this enforcement action.
4 In the absence'of enforcement discretion or overridina issues of Dublic l health and safety. TS ass must be satisfied as-written. Attempts to merely satisfy the intent of an Action Statement are unacceptable. i -6. Factual information related to the following civil penalty escalation or . mitigation factors (see attached matrix and. .; 10 CFR Part 2, Appendix C, Section VI.B.2.):- <
- a. IDENTIFICATION: _ (Who identified the violation? What were the ,
facts and circumstances related to the discovery of the violation? Was it self-disclosing? Was it identified as a result of a generic notification?) : The violation was identified by the resident inspectors reviewina l the licensee's actions in response to the failure of a Trio l Circuit Breaker (TCB) to open durina surveillance testina,
- b. CORRECTIVE ACTION:- Although we expect to learn more-information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
The licensee has maintained that the subject TS AS was confusina l and reauired interoretation. In implementina their j interpretation. the licensee maintains that they achieved the technical eouivalent of the TS-reouired actions: while the inspectors did not consider the AS to be confusina, they did concur that the licensee achieved the functional eauivalent of openina TCB-5. What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? The licensee is considerina the ootion of reauestina a chance to the TS action statement to allow for the electrical isolation of a similarly affected TCB: however. initial indications are that the l action may not be cost-effective. Personnel in the trainina department have speculated that operator trainina, as it relates to the subject TS LC0 and AS. may be modified to discuss this event.
+ TMIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITMOUT THE !
- APPROVAL OF THE REGIONAL ADMINISTRATOR
l
- I
[ .a - , [ 3 ; i ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE ; ., t j, What was the degree of licensee initiative to address the- ! violation and the adequacy of root cause analysis? j [ ~ 4 The 1icensee h6s maintained that the AS was confusina and that an ! l honest effort was made to satisfy its intent. The unit weh j
- ultimately, shut down for the inspection and repair of the sub.iect ;
j TCB: mowever. this was considered a manaaement decision as onnosed ! ! .to a TS reauirement. ; i !
- c. LICENSEE PERFORMANCE: This factor' takes into account the last two i years or the period within the last two inspections, whichever is ;
[ longer. l o List past violations that may be related to the current violation ! {- .(include specific requirement cited and the date issued): ( VIO 335.389/93-22 In this violation, a system enaineer f violated the reauirements of a procedure he deve' oced for { ! L supolvina temporary air to Ultimate Heat Sink isolation valves. j j His rationale inclu_ded. in cart a feelina that the actions he ; i- took met the intent of the-crocedure, if not the written word. : t- ; j Identify the applicable SALP category, the rating for this ; j category and-the overall rating for the last two SALP periods, as , j well as any trend indicated: i SALP Cateaory: Operations !
- The licensee has achieved SALP ratinas of I for the last two SALP !
periods. There have been an increasina number of events ' i associated with Goerations in the cast six months: however, these . l events have not resulted in the identification of a clear trend. l
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities for the i licensee to discover the violation sooner such as through normal surveillances, audits, QA activities, specific NRC or industry
- notification, or. reports by employees? ;
4 . t N2 i. t e. MULTIPLE OCCURRENCES: Were there multiple- examples- of the
- violation identified during this inspection? If there were, ,
J identify the number of examples and briefly describe each one. i There were not multiple examples of this violation identified durina this inspection period. i 2
**THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
l IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR
D 0 4 ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE ;
- f. DURATION: How long did the violation exist?
l This violation existed for aooroximately 1-1/2 hours: the time between when the unit was reauired to enter Mode 3 and when Mode 3 was actually entered. ADDITIONAL COMMENTS / NOTES: e i l i i i i b l l
- THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION.-
IT CAN WOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR
l 4 5 ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE
)
TCB 5 Stuck Shut On July 14, RPS logic. testing conducted in accordance with OP 2-1400059,
" Reactor Protection System.- Periodic Logic Matrix Test," found that-TCB-5 failed to open upon receipt of an open signal from the RPS. Operators attempted to -open the subject TCB from the control room and locally without -
success. Operators declared TCB-5 inoperable at 0330. TS LC0 3.3.1, Table 3.3-1, item 12, required, in part, that 4 channels of TCBs be operable in Mode 1. : Note (f) to the LC0 stated that a "Each channel shall be comprised of two trip breakers; actual trip logic shall be one-out-of-two
-taken twice." The subject LC0 action' statement required that the inoperable channel be placed in the tripped condition within I hour; otherwise, the unit was required to be in Mode 3 within 6 hours.
L As TCB-5 could not be tripped (opened) in its failure mode, operators, in H conjunction with plant management, determined that the intent of the AS could ' be' met by opening TCBs 1, 2 and 6. TCB-1 was the complement to TCB-5 in forming one " channel" as defined by note (f) to TS LCO 3.3.1. TCBs 2 and 6 ' formed another channel of TCBs, electrically located between the CEA MGs and TCBs-1 and 5, respectively. In opening TCB-6, operators effected the i functional equivalent of opening TCB-5. TCBs 1, 2, and 6 were opened at 0418. l The resulting TCB lineup resulted in a TCB trip logic of one-out-of-two taken ' once, with a single channel (comprised of either TCBs 3 and 7 or TCBs 4 and 8) trip required for a reactor trip. i In discussions with the inspector, the licensee stated that they found the TS LCO confusing with regard to the definition of a " channel" of TCBs. The inspector reviewed RPS lesson plans and found that they did not dicuss channels as they relate to TCBs. Further, the licensee stated that the LC0 appeared to have_been written assuming a failed-open TCB. Thus, the decision was made to open TCBs 1, 2, and 6 and consider methods to allow the troubleshooting and repair of TCB-5. At 0750, site management directed that the unit be shut down to affect inspection and repair of TCB-5. The unit was taken off-line at approximately 1050 and entered Mode 3 at 1106. The inspectors concluded that the licensee's actions in opening TCBs.1, 2, and 6 were the functional equivalent of opening TCB-5; however, the inspectors found that the applicable TS AS was prescriptive in requiring that TCB-5 be l opened within I hour or the' unit'placed in Mode 3 within 6 hours. While the i inspectors agreed that the AS did not appear to have considered the failure l mode encountered in TCB-5, they did not agree that the AS was unclear with ~ respect to the actions required following the failure of the breaker. As the l IT CAN BE D SCL ED TSIDE RC li!TH TH APPROVAL OF THE REGIONAL ADMINISTRATOR i 4
. _ __ _ _ _ . _ _ _ _ . _ _ __ _ _ __ _ _ _ _ _ _ - _ - . _ _.m _ . . _ . _ . _ . _ - - . -
N, !, 6 t i ! ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE l - breaker could not be opened, as directed by the AS, the licensee was required to place phce the unit in Mode 3 within 6 hours or to obtain regulatory i relief frorg the requirements of the AS. While the unit was, ultimately, shut 4 down, this was the result of a management decision, not a TS requirement. The { subject AS required entrance into Mode 3 by 0930; the unit actually entered j Mode 3 at 1106. Failure to satisfy the TS AS was identified as a violation i . (VIO 94-15-XX, Failure to Perform TS-Required Shutdown). The trip circuit breakers are of the GE AK2-25 series. Investigation by the l i utility and a GE representative found that a small piece of phenolic broken from the corner of the " cutoff switch", a part of the anti-pump circuitry, had '
- jammed the trip latch lever and prevented the designed circuit breaking action. That switch, which has a two piece cover, has a small screw which holds the cover together and mounts the switch to its mounting plate. This
- switch is assembled at the factory and has not been subject to local maintenance. The failed switch had a loose screw which allowed the contacts ,
l to work around. Contacts out of position could easily cause the type damage + 4 observed, and is judged to be the cause in this case. The licensee performed
- inspections of the balance of the Unit 2 TCBs. While other switches had 4
scratches or " mold marks", all were observed under magnification and found not to be significant. Thus the circuit breaker failure was found to be a random event. The inspectors agreed with the conclusion. 1 i l-a + l i
)
i l 1 a f-1 4
- THIS DOCUMENT CONTAlWS PREDECISIONAL INFORMATION-*
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMIN!$TRATOR
7 ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE NOTICE OF VIOLATION St. Lucie Unit 2. Technical Specification 3.3.1, Table 3.3-1, item 12, !' required, in part, that 4 channels of TCBs be operable in Mode 1. The associated LCO action statement required that an inoperable channel be placed in the tripped condition within 1 hour; otherwise, the unit was required to be in Mode 3 within 6 hours. l l Contrary to the'above, on July 14, Trip Circuit Breaker TCB-5 was i declared inoperable and,- as the breaker's failure mode prevented placing i the affected channel in the tripped condition, the associated shutdown l to Mode 3 was not performed in the required 6 hours. While the unit was ultimately shut down, entrance into Mode 3 occurred approximately 7-1/2 hours after declaring the Trip Circuit Breaker inoperable. Further, the ; shutdown was premised on a management directive, as opposed to a Technical Specification requirement. l While the licensee satisfied the intent of the Action Statement by opening Trip Circuit Breakers TCB-1, TCB-2, and TCB-6, the subject I action statement was prescriptive in requiring that Trip Circuit Breaker l TCB-5 be opened or that the unit be shut down. 4 f 4 i
- THIS DOCUMENT CONTAINS PREDECIS10NAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDF NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR i 4 l
. . - . _ . - - ~ _ - _ . . - - . . - - - . . . . . - . . . - - - . . - . - - -. -. . ..
. . - ~ ! 3/4.3 INSTRUMENTATION l 3/4.3.1 REACTOR PROTECTIVE INSTRUMENTATION ' j LIMITING C0flDITION FOR OPERATION
~
i t
- 3.3.'1 As a minimum, the reactor protective instrumentation channels and
- bypasses of Table 3.3-1 shall be OPERABLE with RESPONSE TIMES as shown in j Table 3.3-2.
l APPLICARILITY: As shown in Taole 3.3-1. 1 ACTION: , As shown in Table 3.3-1. i SURVEILLANCE REQUIREMENTS 4.3.1.1 Each reactor protective instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.3-1. i 4.3.1.2 The logic'for the bypasses shall be demonstrated OPERABLE prior to ' each reactor startup unless performed during the preceding 92 days. The total bypass function shall be demonstrated OPERABLE at least once per 18 months during CHANNEL cal.IBRATION testing of each channel affected by bypass operation. 4.3.1.3 The REACTOR TRIP SYSTEM RESPONSE TIME of each reactor trip function shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least one channel per function such that all channels
. are tested at least once every N times 18 months where N is the total number of redundant chennels in a specific reactor ' trip function as shown in the
" Total No. of Channels" column of Table 3.3-1.
e e o ST. LUCIE - UNIT 2 3/4 3-1
7._._.___.___ 1 IABLE 3.3-1 ) 1: REACTOR PROTECTIVE INSTRUMENTATION
. 8 MINIMUM l M TOTAL N0. CHANNELS CHANNELS APPLICABLE L FlalCTIONAL UNIT OF CHAlelELS TO TRIP OPERABLE MODES ACTION g 1. Manual Reactor Trip 4 2 4 1, 2 1 i
4 2 4 3*, 4*, 5* 5 7 2. Variable Power Level - High 4 2(a)(d) 3 1, 2 2#
- 3. Pressurizer Pressure - High 4 2 3 1, 2 2#
- ~ 4. Thermal Margin / Low Pressure 4 2(a)(d) 3 1, 2 2f l
- 5. Containment Pressure high 4 2 3 1, 2 2f
- 6. Steam Generator Pressure - Low 4/SG 2/SG(b) 3/SG 1, 2 2f l
- 7. ' Steam Generator Pressure i Difference - High 4 2(a)(d) 3 1, 2 2f !
t w 8. Steam Generator Level k Low 4/SG 2/SG 3/SG 1, 2 2f y w 9. Local Power Density - High 4 2(c)(d) 3 1 2f
~
- 10. Loss of Component Cooling Water !
to Reactor Coolant Pumps 4 2 3 1, 2 2#
- 11. Reactor Protection System Logic 4 2 3 1, 2 2f i 3* , 4 *, 5* 5 :
- 12. Reactor Trip Breakers 4 2(f) 4 1, 2 4 !
3*, 4*, 5* 5 :
- 13. Wide Range Logarithmic Neutron Flux Monitor -
g a. Startup and Operating - g Rate of Change of Power - ! g High 4 2(e)(g) 3 1, 2 2f g b. Shutdown 4 0 2 3,4,S 3 i g 14. Reactor Coolant Flow - Low 4/SG 2/SG(a)(d) 3/SG 1, 2 2# l
=
- 15. Loss of Load (Turbine Hydraulic Fluid Pressure - Low) 4 2(c) 3 1 2f
TABLE 3.3-1 (Continued) TABLE NOTATION . I With the protective system trip breakers in the. closed position, the CEA _ drive system capable of CEA withdrawal, and fuel in the reactor vessel. The provisions of Specificati'on 3.0.4 ara not applicable. (a) Trip may be manually bypassed below 0.5% o"' RATED THERMAL POWER in con-junction with (d) below; bypass shall be automatically removed when THERMAL POWER is greater than or equal to 0.,5% of RATED. THERMAL POWER. (b) Trip may be manually bypassed below 705 psig; bypass shall be. automatically removed at or above 705 psig. (c) Trip may be bypassed below 15% of RATED THERMAL POWER; bypass shall be automatically removed when THERMAL POWER is greater than or equal to 15% of RATED THERMAL POWER. (d) Trip may be bypasse'd during testing pursuant to Special Test Exception 3.10.3.
~4 (e) Trip may be bypassed below 10 % and above 15% of RATED THERMAL GWER; bypass shall be automatically removed when THERMAL power is > 10 % or 5 15% of RATED THERhAL POWER. ,
(f) Each channel shall be comprised of two trip breakers; actual trip logic i shall be one-out-of-two taken twice. (g) There shall be at least two decades of overlap between the Wide Range Logarithmic Neutron Flux Monitoring Channels and the Power Range Neutron Flux Monitoring Channels. ACTION STATEMENTS
. ACTION 1 - With the number of channels OP.ERABLE one less than required by ' the Minimum Channels OPERABLE requirement, restore the ~
inoperable. channel to OPERABLE status within 48 hours or be in . at least HOT STAN0BY within the next 6 hours and/or open the protective system trip breakers. 4
.~ .., ..-
-y - . . . . . .
9 4 , . ST. LUCIE - UNIT 2 3/4 3-3
)
d TABLE 3.3-1 (Continued) ACTION STATEMENTS , ACTION 2 (Continued) l
- 6. Cold Leg Temperature Variable Power Level - High (RPS)
Thereal Margin / Low Pressure (RPS) ; Local Power Density - High (RPS)
- 7. Hot Leg Temperature Variable Power Level - High (RPS)
Thermal Margin / Low Pressure (RPS) Local Power Density - High (RPS) i ACTION 3 - With the number of channels OPERABLE one less than required by ! a the Minimum Channels OPERABLE requirement, suspend all l operations involving positive reactivity changes. Verify compliance with the SHUTDOWN MARGIN requirements of Specifica-tion 3.1.1.1 or 3.1.1.2, as applicable, within 1 hour and at
- least once per 12 hours thereafter.
, ACTION 4 - With the number of channels OPERABLE one less than required by the Minimum Channels OPERABLE requirement, STARTUP and/or POWER
- OPERATION may continue provided the res:Lur trip breakers of the inoperable channel are placed in the tripped condition within
- I hour, otherwise, be in at least HOT STANDBY within 6 hours; .
, however, one channel may be bypassed for up to 1 hour, provided 1 the trip breakers of any inoperable channel are in the tripped condition, for surveillance testing per Specificati,on 4.3.1.1.
- ACTION 5 -
With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement restore the inoperable channel to OPERABLE status within 48 hours or open the reactor trip breakers within the next hour. I e e D 4
- 1. _
ST. LUCIE - UNIT 2 3/4 3-5
__-__.... 3 f Qpn 7b7lh5 ' d^ 63M/ gJ 1l,9 z:eq~ FD- U MEMORANDUM FOR: The Commissioners FROM: James M. Taylor Executive Director for Operations
SUBJECT:
ADVISING OCCUPANTS OF FORMERLY-LICENSED SITES OF RELEASE l 0F LIST OF SITES I l On June 22, the Chairman signed a letter to Senator Glenn which attached, among other information, a list of 622 licenses identified by Oak Ridge
- National Laboratory (0RNL) for whkh site contamination could not be ruled out on the basis of information in l' .nse files. The letter also attached a list 1 of 26 sites at which contaminat a had been found as a result of the staff's followup efforts. Of these 26 attes, four have been remediated and released for unrestricted use and six others have been placed on the Site Decommissioning Management Plan (SDMP) list.
! Based on information from the Office of Congressional Affairs (0CA), we believe that Senator Glenn is likely to release these lists, which NRC had not previously released. To respond to anticipated public interest, the staff intends to place the letter to Senator Glenn, including the attachments, in the Public Document Room (PDR) when Senator Glenn releases the lists. We hope to be able to coordinate this release with Senator Glenn's office. In addition, the staff intends to mail a notification, shortly before release
- of the list, to the current owners or occupants of the sites that they are on
- the list and the list is to be made public. The notifications will vary j slightly depending on whether they go to owners of sites that have not yet . been fully reviewed, sites that have been reviewed and cleared, sites with 3 contamination, and sites that were found contaminated and have since been
- remediated. The Regions will coordinate with Agreement States on sites located in those States.
J i
1 MEMORANDUM T0: Those on Attached List FROM: Carl J. Paperiello, Director Office of Nuclear Material Safety and Safeguards
SUBJECT:
ISSUANCE OF LETTERS REGARDING OAK RIDGE NATIONAL LABORATORY (ORNL) LIST OF TERMINATED LICENSES NMSS anticipates that the attached list of 622 terminated licenses identified by ORNL and referred to the Regions for action will shortly be made public by Senator Glenn's office. We believe it is important to attempt to contact as many property owners /former licensees whose properties are on the list as possible to provide them with notice that: 1) their property is.on the list; and 2) media inquiries may be forthcoming. To that end, we have developed four form letters for the Regions to dispatch as soon as possible: the first would go to those properties under review or yet to be reviewed; the second would go to those properties where the Regions have concluded that there are no remaining concerns on residual contamination; the third would go to those properties which have been determined to be contaminated which remain to be cleaned up and the fourth would go to those propertier determined to be contaminated and which have been cleaned up. In the case of terminated licenses located in Agreement States, the Regions should inform the Agreement States of our plans and offer the States the opportunity to inform the property owners /former licensees. The Regions should identify an NRC staff contact for the property owner to refer media inquiries to or to contact if they have questions about their specific property. General questions regarding the purpose, conduct and l methodology of the ORNL study should be referred to Fred Combs in IMNS at 301/415-7265. - We recognize that issuance of and responding to these letters could be labor i intensive and detract significant resources from clearance of the remaining ' sites as well as from ongoing SDMP work. Changes to the regional operating plans to reflect any redirection of resources to support this activity will be made, as necessary. h-
Dear Sir or Madam:
l This letter is in reference to the property listed at the above address. The U.S. Nuclear Regulatory Commission (NRC) has undertaken a review of over l 31,000 previously terminated radioactive materials licenses throughout the United States. The purpose of the review is to confirm that there is documentation to show that licenses terminated from 1954-1985 were terminated in accordance with current NRC criteria. The review has identified over 600 I licenses in which there was insufficient documentation in the NRC's archived l files to conclude that the license was terminated in accordance with today's criteria. ; 1 The property listed above was listed on such a license. While NRC was initially unable to find a clear documented basis to support the license ; termination, a search of our records along with site surveys where necessary i have resolved our concerns regarding this property. To date, we have been able I to find records for 233 sites of the 622 sites sufficient + : lose out our concerns about them. The above listed property is one of 233 sites we have now been able to conclude that we have no remaining t.. as on any residual contamination. It is important for you to know that the entire list of licenses has been provided to Congress at its request and will be released to the public. As a result, you may be contacted by members of the media. If you have questions regarding this letter, you may get in touch with the NRC contact listed below. Sincerely, 4 I CONTACT: (XXX) 555-5555 Letter 2
ENCLOSURE FACILITY FACT SHEET Florida Power and licht Comoany License No. 09-07428-02 Location: St. Lucie Plant Fort Pierce, FL Activity: Sample analysis and preparation and on-site use of calibration sources. ORNL's file review resulted in a ranking / score of 32 for this site based of the following factors:
- 1. The license included both sealed and loose materials.
- 2. Sealed sources or shielding on the license contained large amounts of extremely hazardous materials.
- 3. There was no verifiable decontamination of the site at closeout / license termination.
- 4. There was either no or ina'dequate documentation of materials disposition.
- 5. There was no closeout survey for this site.
Region Il Remarks: 1
- 1. Byproduct license 09-07428-02 was issued on January 14, 1975, for l activities at the licensee's St. Lucie nuclear power plant after an AEC Construction Permit (CPPR-74) had been issued and before a facility operation license was issued.
- 2. On March 1, 1976, Facility Operating License DPR-67 was issued for FP&L's St. Lucie Plant, Unit 1. Paragraphs 2.B(3) and (4) of that l license authorized the licensee to receive, possess and use any byproduct material, without restriction as to chemical or physical form, for reactor startup use, radiation monitoring equipment calibration, and sample analysis.
- 3. Facility Operating License DPR-67 remains in force and continues to authorize the receipt, possession, and use of byproduct material as described above.
Regional Recommendation: Authorization for possession and use of materials was incorporated into Facility Operating License DPR-67. Therefore, no NRC Pction is needed in this case and we recommend that this facility be recved from the list.
Q emuso nw. are my em ~ ~ . . ) there is no inaresse in the prehability of occurrence of as aseidaat previousiy analysed in the saa. i l 2) Does the proposed activity increase the sansequenans of an
- accident previcasly evaluated .f.a the SAAF 1
The eensequenses of as aseident previeuely evaluated in the Shk have i act been increased sitee the performanoe and operatica of the se aos will not be impacted by this change. haditiemally, this change will met areste a new path for uncontrolled radiomative releases and will ' not adversely affect any radiation monitorist equipment er equipment
- which is relied upea to mitigate radiological eensequeases of am
! aooident. . I 2) Does the proposed estivity learnese the pr**f ty of oosurzuses ! of a malfumettom of equipment laportant to safety pewrfously i evaluated in the saa? l The proposed activity slightly siters the method for initiating fuel
< flew from the Doefs to the BDe Day Tanks. Talve vi7218 is moraally 4 a &OCEED OPEN valve that does met require any actuaties 13 order to. .
i b ensure a flew path from the Dosts to the as 30s day tanks. This
! evaluaties alloss vi7ais to be placed in the cLoss posities provided l the identified compensatory actions are implemented. These osapeasatary actions assure the reliability of the EDS fue1 e11 supply. additiemally, oaos vi7318 is opened, the fuel oil transfer i
system fumations se originally designed. As identified in sostien 5 of this evaluation, the failure of V17216
] to eyes (due to either valve or operator failure) is possikia. auch e a failure would result in the less of the 23 BBS due to fuel j j starvation after g = h tely two hours of operation. A risk j assessment was oendueted by ypt's Pen group to determine the shaage j
} ,
in the reliability of the 3 side eleetrical paper system following implementaties of the specified esmpensatory actions. Since the EDS system is caly required te perform its sarety fumaties following a lose of offsite power to the safety elastrioni busee, failures of the j system were taken in eenjunctica with a less of offsite poser. l u. Za the proposed seafi tien, the abange in frequeasy of a less of 1 Q the side elastri peerer is slightly increaseet housvar, this 4 small ineresse'is met eensidered signitioast when eenpled with the i fast that plaat gh will be modified to provide for operators who v111:ba sposta11y instructed to open vi72is as seen as possible
- and vitada 30 minates after an unplanned start of the 23 EDS. Based
- en the 'above, it saa be.ooselnded that the probability of eesarremes of a malfuasties of equipaamt important to safety previously evaluated in the safety analysis report has not been ineressed.
- 4) Does the proposed activity increase the ocasequemens of a malfumation of equipment IE@wi.ent to safety preyhafy evaluated j in the 3ARP i
j The eensequemeen of a malfunation 'of equipment important to safety i previously evaluated in the S&R have met been inerensed since the i most limiting failure von 14 result in.the loss of a single EDS which is sa analysed anat. We other safety systems or equipseat required ] i so a rge 19e ter - aon ho wansaw at:n1 ss '4:se:et s661-12-40
j .. i - l g g FF.oM ED6 FC S M N musg,dunsesda h;e l Pas was ! operability of the subject pipe has been addressed in the referesse 8 i STAR. The suspeeted uneerground leak has been quantifies et i
' appresiastely is gal / day. The 23 DOTW has a design flew rase of 25 GPM (referesse 1) and provides sufficient flow margia to deliver fuel j
j to tanks. the sa sne to maintata the required fuel oil level in the day t l A rish assessment was saaduated by FFL's Paa group. This assessment j used the baseline Unit 2 Pan andel to estimate the change in frogseasy i of less of the 233 4.15kT Dus with a less of grid initiating event and ) the addition of two sew 23 EDs failure medes (i.e., failure of the EDS i fuel oil manual isolation valve to spam and failure of the operater to i open the elesed isolation valve) . A nea-reeevery_ prehability of ) i J 3.01E=3 was used for the operator failing to open the fuel oil
~2 isolaties valve. This probability was based on the es-eentrol model j of Oman using a 120 minute available time and a 30 miante mesa response time.
l Two osses were assessed: j Case 1: Baseline Psa,model ease [ Case 2: i E Baseline andel with the additional failure medes for the 33 l
- EDG (manual fuel oil isolaties valve failing to opes and operator failing to spea the valve).
j V The estimated frequeasy for eask ease is as fe11ews: Case in 1.733-3/yr l Case 2: 1.84E-3/yr 4 This indicates that the additional failure medee resulting from the alesed fuel oil isolation valve results la an appreminate at ehange is i the estimated frequemoy per year of less of the Unit a 233 4.isk? bus. j annetaar i ! Based on the above scenarie, sufficient time exists for an aparator to j. open valve T1721s prior to Dorf as automaticalir starting to replenish EDS 23 day tanks to 342381 levels and sufficient margia eRists free j the as Dora to deliver the required flew rate of fuel to the 33 EDS, i acasidering,the espected ground leakage less. Implementation of the l actione required in section s.4 will provide fumational empenilities ! eenivalent to the original senfiguraties. i i l l t i 1 I 1 l 40'd Z29? 19P cor
- ist f f0 ;use:sa:s at on1 15 Wt:t8? :Oi S661-iE <0
1 i
- s CLOSING REMARKS i (L. Reyes) i i
in closing this predecisional enforcement conference, I remind the , Licensee of two things: j
- First, the apparent violations discussed at this predecisional
, enforcement conference are subject to further review and may be l subject to change prior to any resulting enforcement action.
i
- Second, the statements of views or expressions of opinion made by j NRC employees at this predecisional enforcement conference, or the lack thereof, are not intended to represent final agency determinations i
or beliefs. 4 4 N J 1 i 1 a PROPOSED ENFORCEMENT ACTION - NoT FOR PUBLIC DISCLOSURE WITHouT THE APPROVAL OF THE DIRECTOR. oE
'l I AR Reg f % '
l 0 4h# # 1 l PREDECISIONAL l ENFORCEMENT ! CONFERENCE
- Briefing Materials l ST. LUCIE NUCLEAR PLANT g l AUGUST 19,1996 F
i L -- - -
O NRC CLOSED PREDECISIONAL ENFORCEMENT CONFERENCE ST. LUCIE NUCLEAR PLANTS AUGUST 19,1996 IM TITLE 1 Predecisional Enforcement Conference Agenda 2 Expected Attendees, Meeting Announcement t 3 Opening Remarks and Introductions l l 4 NRC Enforcement Policy { I 5 Summary of the issues l 6 Statement of Concerns / Apparent Violations 7 Inspection Report No. 50-335/389/96-12 4 8 Enforcement Pre-Panel Questionnaire (Configuration Management) 9 Enforcement Pre-Panel Questionnaire (10 CFR 50.59 Safety Evaluations) 10 TIA Response on FPL Safety Evaluation for EDG Fuel Line Isolation 11 Closing Remarks
1 l PREDECISIONAL ENFORCEMENT CONFERENCE AGENDA ST. LUCIE AUGUST 19,1996, AT 1:00 P.M. , NRC REGION ll OFFICE, ATLANTA, GEORGIA
- 1. OPENING REMARKS AND INTRODUCTIONS L. Reyes, Deputy Regional Administrator
- 11. NRC ENFORCEMENT POLICY B. Uryc, Director Enforcement and Investigation Coordination Staff )
lll.
SUMMARY
OF THE ISSUES ) L. Reyes, Deputy Regional Administrator j IV. STATEMENT OF CONCERNS / APPARENT VIOL %TIONS J. Jaudon, Acting Deputy Director Division of Reactor Projects V. LICENSEE PRESENTATION T. Plunkett, President, Nuclear Division Florida Power and Light VI. BREAK / NRC CAUCUS Vll. NRC FOLLOWUP QUESTIONS Vill. CLOSING REMARKS L. Reyes, Deputy Regional Administrator
EXPECTED ATTENDEES 4 Licensee . T. Plunkett, President, Nuclear Division W. Bohlke, Vice President, Engineering A. Stall, Site Vice President, St. Lucie J. Holt, Information Services Supervisor E. Benken, Licensing Engineer NBC 1 L. Reyes, Deputy Regional Administrator, Region II (Rll) J. Jaudon, Acting Deputy Director, Division of Reactor Projects (DRP), Ril A. Gibson, Director, Division of Reactor Safety (DRS), Ril B. Uryc, Director, Enforcement and Investigation Coordination Staff i (EICS), Ril l C. Casto, Chief, Engineering Branch, DRS, Ril
- K. Landis, Chief, Reactor Projects Branch 3, DRP, Ril T. Peebles, Chief, Operating Licensing Branch, DRS, Ril C. Evans, Regional Counsel, Ril M. Miller, Senior Resident inspector, St. Lucie, DRP, Ril E. Lea, Project Engineer, Reactor Projects Branch 3, DRP, Rll ;
L. Mellen, Project Engineer, Reactor Projects Branch 3, DRP, Rll i L. Wiens, Senior Project Manager, Reactor Projects ll/2, NRR !
OPENING REMARKS AND INTRODUCTIONS l (L. Reyes) Good morning. I am Luis Reyes, Deputy Regional Administrator for the l Nuclear Regulatory Commission's Region ll Office. This morning we will conduct a predecisional enforcement conference between the NRC l and St. Lucie which is CLOSED to public observation. ! The agenda for the conference is shown in the viewgraph. Following my brief opening remarks, Mr. Bruno Uryc, the Director of the Region 11 Enforcement Staff, will discuss the Agency's Enforcement Policy. I will i then provide introductory remarks concerning my perspective on the i events to be addressed today. Johns Jaudon, Acting Deputy Director 1 of the Division of Reactor Projects, will then discuss the apparent I violations. You will then be given an opportunity to respond to the ; apparent violations. In this regard, I wish to reiterate to you that the decision to hold this conference does not mean that the NRC has determined that violations have occurred or that enforcement action will be taken. This conference is an important step in arriving at that decision. ,
l l l Following your presentation, I plan to take about a 10-minute break so that the NRC can briefly review what it has heard and determine if we I have follow-up questions. Lastly, I will provide concluding remarks. At this point, I would like to have the NRC staff introduce themselves and then ask you to introduce your participants. [lNTRODUCTIONS] .i Thank you. i Mr. Uryc will now discuss the Agency's Enforcement Policy. 4 rj
NRC ENFORCEMENT POLICY (B. Uryc) l NRC Enforcement Poliev and Procedure After an apparent violation is identified, it is assessed in accordance with the Commission's Enforcement Policy, which was recently revised and became effective on June 30,.1995. The Enforcement Policy has been published as NUREG-1600. The assessment of an apparent violation inve; es categorizing the apparent violation into one of four severity levels based on safety and regulatory significance. For cases where there is a potential for escalated enforcement action, that is, where the severity level of the apparent violation is categorized at Severity L'avei I, ll, or Ill, a predecisional enforcement conference is held. There are three primary enforcement sanctions available to the NRC and they are Notices of Violation, civil penalties, and orders. Notices of Violation and civil penalties are issued based on identified violations. Orders may be issued for violations, or, in the absence of a violation, because of a significant public health or safety issue.
This predecisional enforcement conference is essentially the last step j of the inspection or investigation process before the staff makes its i
- final enforcement decision.
I The purpose of this conference is not to negotiate a sanction. Our purpose here today is to obtain information that will assist'us in - determining the' appropriate enforcement action, such as: (1) a 1 - common understanding of the facts, root causes and missed opportunities associated with the violations, (2) a common understanding of corrective action taken or planned, and (3)'a common understanding of the significance of issues and the need for lasting comprehensive action. The apparent violations discussed at this conference are subject to further review and they may be subject to change prior to any resulting enforcement action. .It is important to note that the decision to l conduct this conference does not mean that NRC has determined that a violation has occurred or that enforcement action will be taken. l 1 l 1
i- - L I should also note at this time that statement of views or the ;
- expression of. opinion made by the NRC staff at this conference, or the
/ack thereof, are not intended to represent final determinations or l
f' beliefs. i' . 1
! t l- Following.the conference, the Regional Administrator in. conjunction -
with the NRC Office of Enforcement and other NRC Headquarters of' ices will reach an enforcement decision. This process should'take j about four weeks to accomplish. h Predecisional enforcement conferences are normally closed to the public as is this conference. However, the Commission implemented a l trial program in July 1992 to allow certain enforcement conferences to ) be open for public observation. (July '10,1992 - Federal Register] ) This trial program was recently extended for additional evaluation. Finally, if the final enforcement action involves a proposed civil penalty or an order, the NRC willissue~a press release 24 hours after the enforcement action is issued. I 1
SUMMARY
OF THE ISSUE (L. Reyes) Issues: 50.59 Safety Evaluations and Configuration Management Process This is a Predecisional Enforcement Conference to discuss apparent violations in two areas; conformance with 10 CFR 50.59 and configuration management. Four apparent violations were identified in the area of 10 CFR 50.59 evaluations. Five examples of one apparent violation were also noted in the area of configuration management. The apparent 10 CFR 50.59 violations are of concern because they indicate that weaknesses exist in both recognizing the need for safety evaluations and in the process applied in assessing the impact of changes upon the plant. The apparent violation in the area of configuration management is of concern because it indicates that deficiencies have existed in l configuration management processes which have manifested
t themselves in failures to ensure that the design of the plant was properly incorporated into plant procedures and drawings. No plant event has been tied to the inaccuracies thus far identified; however, we are concerned about the potential extent of these conditions. { 1
. . , . . . . , . . . ~
l STATEMENT OF CONCERNS / APPARENT VIOLATION (J. Jaudon) Issue: Configuration Management Several examples of failures to incorporate design changes or constraints properly into plant procedures and drawings were identified. Defcet: The apparent violation included five examples :
- 1) One licensee-identified example of a failure to update an operating procedure to include operational limitations on the commencement of a full core offload. The limitations were imposed by a Plant Change / Modification which included a spent fuel pool heat load calculation.
- 2) One example of a failure to update an annunciator response summary when a hydrazine tank low level alarm setpoint was changed via Plant Change / Modification.
1 l
3) One example of a f ailure to update an engineering drawing to reflect the deletion, via Plant Change / Modification, of valves and piping for intake Cooling Water System Pump Lubrication. 4) One example of a failure to update an annunciator response summary to reflect a change, made via Plant Change / Modification, which removed automatic and control room operation capability from a pair of Intake Cooling Water valves. 5) One examp;? of a failure to update an annunciator response procedure to reflect a change, made via Plant Change / Modification, which removed the alarm function when placing Atmospheric Steam Dump Valve Selector Switches in manual. The appa'.ent violation identified above has been determined to be similar to annunciator response summary deficiencies identified in previous inspection reports. As a result, we are concerned that the
extent of condition of configuration management deficiencies may not-yet be known. Consequences: The failures to update annunciator response procedures and drawings following design change implementation resulted in providing inaccurate or misleading information to control room operators. In the E case of not properly incorporating the spent fuel pool heat load calculation into operational procedure limitations, a full core off-load was commenced without verifying or establishing appropriate parameters.
STATEMENT OF CONCERNS / APPARENT VIOLATION (J. Jaudon) lssue: 50.59 Safety Evaluations 1 1 I l l Several safety evaluations or issues which potentially required safety i evaluations were found. Problems were identified with four of the items reviewed. The items of concern spanned the areas of whether ch'anges were properly considered for applicability under 10 CFR 50.59, the adequacy of 50.59 screenings, and conclusions reached during 50.59 evaluations. The four apparent violations, and their associated consequences, are as follows.
- 1) A failure to perform a safety evaluation for the construction of the Unit 2 Control Element Drive Mechanism Control System room was identified. The room had been constructed during the preoperational test phase of the unit and this failure was identified in June 1996.
I
Upon conducting an evaluation of the room, it was identified that modifications to supports aid restraints for non-safety- 'i i 1 related components were required to ensure that the subject components did not adversely affect safety-related + i components during a seismic event. l
- 2) 'A failure to identify that the installation of a temporary fire i pump represented a change to the plant as described in the UFSAR was identified. The gasoline-powered pump was installed as a replacement for an electrically driven pump, and this change resulted in a change to the P&lD for the fire protection system provided in the UFSAR and the pump's capacity was lower than that for the pump it replaced.
The consequences of this action were that a safety i ,
- evaluation of the proposed alteration's impact on an I i
operable plant system was not performed. i a j
- 3) The 10 CFR 50.59 screening process failed to identify that ;
I refueling machine underload and overload setpoints were l l I
jncluded in the.UFSAR. This led to'a failure to perform a' ; required safety evaluation. i The consequences of this failure were minimal, in that the ! licensee's Facility Review Group identified the failure in the screening process as a function of their activities prior to ; recommanding approval. j
- 4) An example of a failure to recognize an unreviewed safety question was identified in making a valve lineup change to ~
f the emergency diesel general fuel oil transfer system, l reliance on operator action replaced automatic action and i i i introduced new failure modes to the emergency diesel generator. This increased the probability of malfunction of a component important to safety. As a consequence of making the change without recognizing the increased probability of failure, prior NRC approval was not obtained for the change in question. i l
Our findings are documented in NRC Inspection Report 50-335, ! 389/96-12, which were transmitted to you on July 26,1996. At this I conference, we are affording you the opportunity to provide information relative to: i e Any errors the inspection reports i e The severity of the violations ; I 1 e Any escalation or mitigation considerations l e Any other application of the Enforcement Policy relevant to this issue. l
ISSUE TO BE DISCUSSED 10 CFR 50 Appendix B, " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," Criterion ill requires, in part, that measures be established to assure that applicable regulatory requirements and the design basis for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions.
- 1. The licensee failed to incorporate the prerequisite conditions contained in PC/M 054-196, supplement 0, "St. Lucie Unit 1 Cycle 14 Reload," into OP 1-1600023," Refueling Sequencing Guidelines." As a result, requirements for the operation of two Spent Fuel Pool Cooling Pumps, maximum initial Spent Fuel Pool temperature, minimum time since shutdown, minimum Component Cooling Water system flow to the Spent Fuel Pool heat exchangers, and operability of control room annunciation were not verified prior to the initiation of fuel offload.
l l
- 2. PC/M 109-294 (Setpoint change to the Hydrazine Low Level l Alarm (LIS-07-9)] was completed without assuring that affected procedure ONOP 2-0030131, " Plant Annunciator Summary," was j revised. This resulted in annunciator S-10, "HYDRAZINE TK ;
LEVEL LO," showing an incorrect setpoint of 35.5 inches in the ! procedure.
- 3. During implementation of PC/M 341-192 [lCW Lube Water Piping Removal and CW Lube Water Piping Renovation), the as-built Dwg. No. JPN-341-192-008 was not incorporated in Dwg. No.
8770-G-082, " Flow Diagram Circulating and Intake Cooling Water System," Rev 11, sheet 2 issued May 9,1995 for PC/M 341-192. This resulted in Dwg. No 8770-G-082 erroneously showing valves l-FCV-21-3A & 3B and associated piping still installed.
- 4. PC/M 268-292 IICW Lube Water Piping Removal and CW Lube Water Piping Renovation) was completed without assuring that affected procedure ONOP 2-0030131, " Plant Annunciator l
[ Summary," was revised. This resulted in annunciator E-16, i
" CIRC WTR PP LUBE WTR SPLY BACKUP IN SERVICE," l incorrectly requiring operators verify the position of valves MV- l 21-4A & 4B following a SIAS signal using control room indication. l These valves no longer received a SIAS signal, were deenergized ;
s and had no control room position indication. l
- 5. PC/M 275-290 [FIS-14-6 Low Flow Alarm and " Manual" Annunciator Deletions] was completed without assuring that ;
affected procedure ONOP 2-0030131, " Plant Annunciator l Summary," was revised. This resulted in safety-related annunciators LA-12, "ATM STM DUMP MV-08-18A/18B ; OVERLOAD /SS ISOL," and LB-12, "ATM STM DUMP MV 19A/19B OVERLOAD /SS ISOL," incorrectly requiring operators to ; check Auto / Manual switch or switches for the MANUAL position. ,
- The relay contacts which energized these annunciators based on l switch position were removed to eliminate nuisance alarms.
l l !
- NOTE
- The apparent violations discussed in this predecisional l enforcement conference are subject to further review and are subject to change prior to any resulting enforcement decision.
I i I a I 4
ISSUE TO BE DISCUSSED 10 CFR 50.59, " Changes, Tests and Experiments," stated, in part, that ! a licensee may make changes in the facility as described in the safety l analysis report without prior Commission approval, unless the proposed change involves an unreviewed safety question, and that the licensee I shall maintain records of changes in the facility. i
- 1. The licensee erected an enclosure around the Control Element i Drive Mechanism Control System during the Unit 2 preoperational i test phase without performing a safety evaluation. This non- !
safety related structure was erected in a safety related cable spread room, i
- 2. During the 1996 Unit 1 refueling outage the licensee installed a temporary, 750 gpm, fire pump arranged to take suction from fire protection water tank 1B and discharge into the fire protection water system via fire hydrant No.12 without performing the l required safety evaluation. '
- 3. The licensee used an engineering evaluation to change the set peints and procedures described in the FSAR for operating the fuel hoist without performing a 10 CFR 50.59 safety analysis / evaluation.
- 4. The licensee made a change to the facility which involved an unreviewed safety question when the 2B Emergency Diesel Generator fuel oil line from the fuel oil tank to the day tank was manually isolated to secure a through-wall fuel oil leak. In taking the action, the licensee introduced two failure modes into the 2B Emergency Diesel Generator, which necessarily increased the probability of occurrence of a malfunction of the Emergency Diesel Generator above that previously evaluated in the safety evaluation report, resulting in an unreviewed safety question.
NOTE: The apparent violations discussed in this predecisional enforcement conference are subject to further review and are subject to change prior to any resulting enforcement decision.
I ENFORCEMENT ACTION WORKSHEET l INADEQUATE CONFIGURATION MANAGEMENT PREPARED BY: Mark S. Miller DATE: July 1, 1996 NOTE: The Section Chief of the responsible Division is responsible for preparation of this EAW and its I distribution to attendees prior to an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e-mail [ENF.GRP, CFE, OEMAIL, JXL, JRG, SHL, LFD; appropriate Ril DRP, DRS: appropriate NRR, NMSS). A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is required. Copies of applicable Technical Specifications or license conditions crted in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed. This Notice has been reviewed by the Branch Chief or Divisjon Director and each violation includes the appropriate level f specifi ty a,s to how and when the requirement was violated. e
//
. M&E dWu )
/ Sig ure '
Facility: bT. ( L'c4 E Unit (s): Docket Nos: License Nos: Inspection Report No: Inspection Dates: Lead Inspector: ; i
- 1. Brief Summary of Inspection Findings: [Always include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then, either summarire the inspection findings in this section or reference and attach sections of the inspection report.
inspectors are encouraged to utilize the Noncompliance Information Checklist provided in Enclosure 4 to ensure that the information gathered to support the violation is complete.) l A number of unrelated findings over three inspection periods has indicated that the licensee has inadequately managed configuration control, particularly in the area of ensuring that design changes are reflected in procedures. A number of annunciator response summary procedures have been found to include erroneous information, and several have been traced back to the hardware changes which rendered the procedures inaccurate. While none of the individual occurances (with' respect to annunciators) presented high safety significance, the findings have illustrated an ongoing failure to properly factor design changes into procedures due. primarily, to a failure to identify, up front, the procedures which would be affected and to properly track the procedure revisions to closure. In addition to the annunciator issues. one drawing was identified as having been overlooked in the design change process. and one procedural deficiency, identified by the licensee is identified. The licensee-PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
ENFORCEMENT ACTION woRKsussT , identified issue involved a failure to include prerequisites in a procedure which would have been required to ensure the validity of the licensee's full core offload spent fuel pool heat load calculations. , Core offload began before the failure was identified, and 7 assemblies were offloaded before operations were secured and corrective actions taken. See attached IR feeder and proposed NOV for details. e e 2 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
.-. .- . . _ _ _~ . - . . - ._ . . .. --- .
l tr6cRCENsNT ACTIoM woaxsassT
- 2. . Analysis of Root Cauce: i Lack of formality in the licensee's program for preparing and implementing Plant Change / Modifications (PC/Ms), whicn did not l explicitly require that affected procedures be identified and :
reviewed / changed during the development and execution of PC/Ms. l
- 3. Basis for Severity Level (Safety Significance): linclude example from the l supplements, aggregation, repetitiveness, wiHfulness, etc.]
l 1 Aggregation of examples and application of Supplement I, C.7, a breakdown in the control of licensed activities involving a number of . violations that are related that collectively represent a potentially I ! significant lack of attention toward licensed activities, j While safety significance with respect to annunciator response procedure
- issues is difficult to assess,.the number of examples identified (both 1
in the citation and in addition to the citation) by NRC indicate that a weakness in incorporating design changes into procedures has existed for some time. Additionally, the licensee-identified portion of the
. violation (involving a failure to include calculational assumptions as prerequisites in operational procedures) represented a challenge to the Spent Fuel Pool's ability to remove the decay heat associated with a full core offload.
4
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
(by EA#, Supplement, and identification date.] l EA 96-040 - Boron Overdilution Event, Supplement 1, 1/22/96 ; EA 95-180 - Inoperable PORVs due to Inadequate PMT, Supplement 1, 8/4/95 4
- 5. Identification Credit? No The configuration management issue was raised by NRC initially in March, j 1996, as walkdowns of annunciators indicated that inaccuracies were
- frequent in annunciator response procedures. The issue grew through 5/96, with additional examples identified and the sources of some of the inaccuracies (PC/M implementation) being identified by NRC. Licensee j corrective action began in late April, when we identified drawing errors and additional annunciator response procedure errors.
Enter date Licensee was aware of issues requiring corrective action: [4/96]
- 6. Corrective Action Credit? Yes 4
Brief summary of corrective actions:
}
l In response to the issue, the' licensee adopted corrective actions which
; included:
o Implementing design control processes from Turkey Point, which
)
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE a
ENFORCEMENT ACTION -4 - WoRKOREET provided more positive control over the initial reviews and q documentation of required actions for PC/Ms. ! e Performing reviews of all Unit 1 outage related PC/Ms to ensure ; that required procedural changes were identified'. e Requiring that all PC/M paperwork for modifications installed during the current Unit 1 outage be closed out prior to returning 1 the affected system to service. ; e Revalidating open items from previous PC/Ms on both units and establishing timelines for closure of the open items.
-e Initiating a vertical slice inspection of selected, PRA-significant (EDGs, HPSI, and CCW), systems to ensure that the systems were properly installed and that procedures were adequate.
Explain application of corrective action credit: Corrective action appears to be of appropriate scope.
- 7. Candidate For Discretion? Yes Explain basis for discretion consideration:
Licensee's performance has been considered superior in the past.
- 8. Is A Predecisional Enforcement Conference Necessary? No
- 9. Non-Routine Issues / Additional Information:
PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE I
ENFokCEMENT ACTION WoRKSHEET
- 10. This Action is Consistent With the FolloWing Action (or Enforcement Guidance) Previously Issued: [EICS to provide] [lf inconsistent, include:j Basis for Inconsistency With Previously Issued Actions (Guidance) i
- 11. Regulatory Message:
1 Positive control must be established and maintained over the design ; change process, with particular emphasis on ensuring that design ! features and constraints are properly incorporated into procedures and l drawings.
- 12. Reconnended Enforcement Action: l i
SL IV i
- 13. Thi . Case Meets the Criteria for a Delegated Case. (EICS Enter Yes or Nol l
- 14. Should This Action Be Sent to OE For Full Review 7 (EICS - Enter Yes or No1 If yes why: l l
- 15. Regional Counsel Review (EICS to obtain]
No Legal Objection Dated:
- 16. Exempt from Timeliness: [EICS)
Basis for Exemption: Enforcement Coordinator: DATE: PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
ENFORCENENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION [] Problems categorized at Severity Level I or II. [] Case involves overexposure or release of radiological material._in excess of NRC requirements.
- ] - Case involves particularly poor licensee performance.
[J. Case (may)_ involve willfulness. Information should be included to address whether or not the region has had discussions with 01 regarding the case, whether or not the matter has been formally referred to 01, and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included.
- ] Current violation is directly repetitive of an earlier violation.
- ] Excessive duration of a problem resulted in a substantial increase in i risk. l
- Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit.
[] Cases involves the-loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.)
- ] Licensee's sustained performance has been particularly good.
[] Discretion should be exercised by escalating or mitigating to ensure that the proposed civil penalty reflects the NRC's concern regarding the violation at issue and that it conveys the appropriate message to the licensee. Explain.
'l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
Enclosure 3 REFERENCE DOCUMENT CHECKLIST [X] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: 96-08 [ ]' Licensee reports: )
- i
[] - Applicable Tech Specs along with bases: i i , [] Applicable license conditions [] Applicable licensee procedures or extracts [] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results 1 [] Extracts of pertinent FSAR or Updated FSAR sections for citations l involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [] Other miscellaneous documents (List): l l I PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Inspection Report 96-04 identified several potential configuration control weaknesses involving inaccuracies in control room annunciator response summaries and engineering drawings. Of the deficiencies noted, one was tied to an inadequacy in the implementation of a PC/M. . Unresolved Item 96-04-05, " Configuration Control Management," was opened to track the issue while the inspection scope was expanded. inspection Report 96-06 documented additional deficiencies, identified during system walkdowns, which were the result of PC/M implementation inadequacies. During the current inspection period, additional PC/M implementation issues were identified. The individual issues are as follows: , e IR 96-04 documented the fact that, on January 6, 1995, the licensee closed out PC/M 109-294 [Setpoint change to the Hydrazine Low Level Alarm (LIS-07-9)] without assuring that affected procedure ONOP 2-0030131, " Plant Annunciator Summary", was revised. This resulted in annunciator S-10 HYDRAZINE TK LEVEL L0 showing an incorrect setpoint of 35.5 inches. e IR 96-06 documented the fact that, on May 16, 1994, the licensee closed out PC/M 341-192 [lCW Lube Water Piping Removal and CW Lube Water Piping Renovation]. The as-built Dwg. No. JPN-341-192-008 i was not incorporated in Dwg. No. 8770-G-082, " Flow Diagram i circulating and Intake Cooling Water System", Rev 11, sheet 2 l issued May 9, 1995 for PC/M 341-192. This resulted in Dwg. No l 8770-G-082 erroneously showing valves I-FCV-21-3A & 38 and i associated piping still installed. l 1 e IR 96-06 documented the fact that, on February 14, 1994, the licensee closed out PC/M 268-292 (ICW Lube Water Piping Removal and CW Lube Water Piping Renovation] without assuring that affected procedure ON0P 2-0030131, " Plant Annunciator Summary", was revised. This resulted in annunciator E-16 CIRC WTR PP LUBE WTR SPLY BACKUP IN SERVICE incorrectly requiring operators verify the position of valves MV-21-4A & 4B following a SIAS signal using control room indication. These valves no longer received a SIAS signal, were deenergized and had no control room position indication. e This inspection report documents the fact that, on October 28, 1992, the licensee closed out PC/M 275-290 [FIS-14-6 Low Flow Alarm and " Manual" Annunciator Deletions] without assuring that affected procedure ON0P 2-0030131. " Plant Annunciator Summary", was revised. This resulted in safety-related annunciators LA-12 ATM STM DUMP MV-08-18A/188 OVERLOAD /SS ISOL and LB-12 ATM STM DUMP MV-08-19A/19B OVERLOAD /SS ISOL incorrectly requiring operators to check the Auto / Manual switch or switches at RTGB-202 and PACB for the MANUAL position. The relay contacts which energized these annunciators based on switch position were removed to eliminate nuisance alarms. e During the current inspection period, the licensee identified the fact that assumptions made in the heat load calculation supporting the Unit I full core offload were not appropriately factored into PROPOSED ENFORCEMENT ACTION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
the applicable procedure. Specifically, PC/M 054-196 supplement 0 0, St. Lucie Unit 1 Cycle 14 Reload," included, in Attachment 8, operational limitations which resulted from the heat load i calculation performed to support the full core offload. These included: e Ensuring that initial SFP temperature was less than or equal ! to 106*F. 1 e Ensuring that the reactor was subcritical for at least 168 1 hours prior to commencing the offload. l e Verifying that the SFP high temperature alarm, which 1 annunciated in the control room, was operable.
.I e Verifying that two SFP cooling pumps were in operation. j
. 1 e Verifying that CCW flow to the fuel pool he~at exchangers was i maintained at approximately 3560 gpm when two SFP cooling pumps were operating.
On May 12,.the licensee's QA organization identified these deficiencies after the offload of 7 fuel assemblies. The defueling evolution was subsequently stopped, and the prerequisites were added to OP 1-1600023, " Refueling Sequencing Guidelines," as revision 62 to the procedure. Only four examples of inaccurate annunciator response summaries are cited above; those being inaccuracies for which the inspectors determined which PC/M resulted in the inaccuracies. IR 96-06 summarized recent NRC findings in this area, and stated that ten examples of alarm , setpoint inaccuracies and 18 other (e.g. wrong sensing element, wrong i action directed) inaccuracies in the Annunciator Response Summaries had i been identified in both units' ICW and CS systems. 10 CFR 50 Appendix B, Criterion III, " Design Control," requires, in part, that measures be established to ensure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The licensee's Topical Quality Assurance Report, TQR 3.0, revision 11, " Design Control," included the following provisions: e Section 3.2.2, " Design Change Control," stated, in part, " Design changes shall be reviewed to ensure that implementation of the design change is coordinated with any necessary changes to operating procedures..."
- e. Section 3.2.4, " Design Verification," stated, in part, that
" Design control measures shall be established to independently verify that design inputs, design process, and that the design inputs are correctly incorporated into design output."
The inspectors concluded that the examples cited above failed to satisfy these criteria and, therefore, constituted a violation (VIO 96-08-XX,
" Failure to Adequately Manage Configuration Control"). In the cases of PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
i I i . e procedural inadequacies. brought on by the implementation of PC/Ms c the. l inspectors concluded that a lack of detailed.preimplementation reviews ! existed with respect-to the impact of a given PC/M on procedures. While *
- preparing PC/Ms, the licensee included a review for impact to other
. organizations' procedures and documented potential impacts on PC/M revi&w #c ms; Fowem this dec.acntation acunted to a "yes" or "no" ;l determination, as opposed to specifying the procedures which required l revision._ As a result, no formal process tracked the completion ofL !
formally specified actions. : i- ! The. licensee's QA organization performed an audit of this area.and : documented their findings in QSL-PCM-96-11, "PC/M Design Control." The ! licensee found the following with regard to the process: i e Plant procedures and instructions did not adequately define the i review and comment process by-~ plant departments impacted by PC/Ms j 3- or the resolution to those comments. . 1 Y e Plant procedures and instructions did not adequately address the ! .. identification of plant procedures impacted by PC/Ms. l i ' I Plant procedures and instructions did not adequately address the e' l review of Safety Evaluations for impact on plant procedures and I instructions (this applied to Safety Evaluations which included conditions to ensure that the assumptions in the evaluations were
- maintained valid). ;
i The inspectors found the licensee's findings to be in general agreement ) [ with. observations made by the NRC. i i In response to the issue, the licensee adopted corrective actions which- i included: l e Implementing design control processes from Turkey Point, which provided more positive control over the initial reviews and documentation of. required' actions for PC/Ms. e Performing reviews of all Unit 1 outage related PC/Ms to ensure that required procedural changes were identified. e Requiring that all PC/M paperwork for modifications installed during the current Unit 1 outage be closed out prior to returning the affected system to service. e Revalidating open items from previous PC/Ms on both units and establishing timelines for closure of the open items. 1 e Initiating a vertical slice inspection of selected. PRA-significant (EDGs, HPSI, and CCW), systems to ensure that the ; systems were properly installed and that procedures were adequate. The inspector. concluded that the licensee had moved aggressively to address the PC/M issues discussed above and to ensure that the as-built configuration of the plant was adequate. The overall adequacy of the .; licensee's actions will be' determined in followup inspections to the PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE _ WITHOUT THE APPROVAL OF THE DIRECTOR. OE
1 violation described above. I l E
.p 1
l l 1 1 i i
.I i
i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
10 CFR 50 App:ndix B, " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," Criterion III required, in part, that measures be established to assure that applicable regulatory requirements and the design basis for those structures, systems, and components to which this appendix applies are correctly translated into specificationr, drawings, procedures, and instructions. FPL Topical Quality Assurance Report, TQR 3.0, revision ll, " Design Control," Section 3.2.2, " Design Change Control," stated, in part, " Design changes shall be reviewed to ensure that implementation of the design change is coordinated with any necessary changes to operating procedures..." Section 3.2.4, " Design Verification," stated, in part, that " Design control measures shall be established to independently verify the design inputs, design process, and that the design inputs are correctly incorporated into design output." Contrary to the above:
- 1. On January 6,1995, the licensee failed to coordinate a design change with an operational procedure change when PC/M 109-294 1
[Setpoint change to the Hydrazine Low Level Alarm (LIS-07-9)] was completed without assuring that affected procedure ON0P 2-0030131,
" Plant Annunciator Summary," was revised. This resulted in l annunciator S-10 "HYDRAZINE TK LEVEL LO," showing an incorrect setpoint of 35.5 inches in the procedure. ;
- 2. Dr. May 16, 1994, the licensee failed to perform an adequate independent verification of design output in the implementation of.
PC/M 341-192 [ICW Lube Water Piping Removal and CW Lube Water i Piping Renovation]. The as-built Dwg. No. JPN-341-192-008 was not ; incorporated in Dwg. No. 8770-G-082, " Flow Diagram Circulating and ! Intake Cooling Water System," Rev 11, sheet 2 issued May 9, 1995 for PC/M 341-192. This resulted in Dwg. No 8770-G-082 erroneously showing valves I-FCV-21-3A & 3B and associated piping still installed.
- 3. On February 14, 1994, the licensee failed to coordinate a design change with an operational procedure change when PC/M 268-292 [ICW ,
Lube Water Piping Removal and CW Lube Water Piping Renovation] was ] completed without assuring that affected procedure ONOP 2-0030131, -
" Plant Annunciator Summary," was revised. This resulted in annunciator E-16, " CIRC WTR PP LUBE WTR SPLY BACKUP IN SERVICE," .
incorrectly requiring operators verify the position of valves MV- ! 21-4A & 4B following a SIAS signal using control room indication. These valves no longer received a SIAS signal, were deenergized and had no control room position indication.
- 4. On October 28, 1992, the licensee failed to coordinate a design change with an operational procedure change when PC/M 275-290
[FIS-14-6 Low Flow Alarm and " Manual" Annunciator Deletions) was completed without assuring that affected procedure ONOP 2-0030131,
" Plant Annunciator Summary," was revised. This resulted in safety-related annunciators LA-12. "ATM STM DUMP MV-08-18A/188 OVERLOAD /SS ISOL," and LB-12, "ATM STM DUMP MV-08-19A/19B OVERLOAD /SS ISOL," incorrectly requiring operators to check i Auto / Manual switch or switches for the MANUAL position. The relay PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
~
- contacts which enzrgized these annunciators based on switch !
position were removed to eliminate nuisance alarms. , 1
- 5. On May.12, 1996, the licensee failed to coordinate a design change i j- with an operational procedure change when Unit I fuel offload was j
, commenced without incorporatim.r the prerequisite conditions . contained in PC/M 054-196, supplement 0, "St. Lucie Unit 1 Cycle ! i~ 14 Reload," into OP 1-1600023, " Refueling Sequencing Guidelines.", As a result,. requirements for the operation of two Spent Fuel Pool . e Cooling Pumps, maximum initial Spent Fuel Pool temperature, ! 4 minimum time since shutdown, minimum Component Cooling Water ; system flow to the Spent Fuel Pool heat exchangers, and i operability of control room annunciation were not verified prior to the initiation of fuel offload (minimum requirements for operating Spent Fuel Pool pumps and component cooling water flow ! 4 were not met at the time fuel movement was initiated). 3 I ;
. t l
3 + i I i ! I I Y l l l
$ l PROPOSED ENFORCEMENT ACTION - NOT FOR PL'8LIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE a
t
ENFORCEMENT ACTION WORKSHEET INADEQUATE SAFETY EVALUATION PROGRAM PREPARED BY: John W. York DATE: July 7, 1996 NOTE: The Branch Chief of the responsible Division is responsible for preparation of this EAW and its distribution to attendees prior to an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and telephone bridge rusnoer to attendees via e mail (ENF.GRP, CFE, OEMAIL, JXL, JRG, SHL, LTD; appropriate Ri! DRP, DRS; appropriate NRR, NMSS). A Notice of Violation (without "boilerplate") which includes the reconsnended severity level for the violation is required. Copies of applicable Technical Specifications or license conditions cited in the Notice or other reference material needed to evaluate the proposed enforcement action are required to be enclosed. This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated. Signature f Facility: St. Lucie Unit (s): 1 and 2 Docket Nos: 50-335, 389 j License Nos: DPR-67, NPF-16 Inspection Report No: 96-12 Inspection Dates: ?? ! Lead Inspector: John York ; 1
- 1. Brief Summary of Inspection Findings: lAtways include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then, either suirnarize the inspection findings in this section or reference and attach sections of the inspection report. Inspectors are encouraged to utilite the Noncompliance Information Checklist provided in Enclosure 4 to ensure that the information gathered to support the violation is complete.)
Four examples were identified for violation of 50.59 requirements: ! Examole 1-The licensee concluded using PRA techniques that closing a manual valve (because of a leak in the transfer line) to the day tank of i the EDG would increase the probability of a failure of the EDG by 6 %. However, in considering 50.59 criteria, the licensee concluded no increase in probability of component failure and therefore no Unreviewed Safety Question wa: identified. Example 2-An enclosure was fabricated in a safety related area without performing a safety evaluation (50 59), i.e. no seismic analysis, etc. Example 3-Fire protection plan requires that two 2300 gpm fire pumps be operable at all times. During a refueling outage, electrical configuration was such that one of the pumps was removed from service and a smaller (750 gpm) pump was installed. This violated the fire protection configuration in the UFSAR and requires a 50.59 evaluation. Example 4-The licensee changed the refueling hoist interrupt setpoints PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
ENFOICEMENT ACTIcN woRKSHEET with only an engineering analysis. Since the set points were outside the UFSAR values a 50.59 safety analysis was required.
~~~ ~
1 See attached IR feeder and proposed NOV for detailsS"
- 2. Analysis of Root Cause:
Attention to detail, inadequate review of UFSAR in the 50.59 process.
- 3. Basis for Severity Level (Safety Significance): tinctude ex w ie from the supplements, aggregation, repetitiveness, willfulness, etc.)
The number of examples indicate a programatic breakdown and lack of management oversight of 50.59 such that a safety concern is present regarding compliance with the requirements of 50.59. Also, a condition existed where a required license amendment was not sought, i.e., an USQ existed and the condition was not sent to the NRC for review.
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
] (by EA#, Supplement, and Identification date.) 1 j None identified?
- 5. Identification Credit? Depends on the example.
Item 1-Inspectors identified that the licensee did not identify an Unreviewed Safety Question. (No) , Item 2-In response to an alarm and related maintenance, the licensee identified that an enclosure in a cable spread room (safety related
- area) did not have a safety analysis. (No)
- Item 3-Inspectors identified and questioned a different size fire pump.
(No) Item 4-Licensee STA and safety commmittee identified that a 50.59 safety analysis had not been performed. (Yes) l Enter date Licensee was aware of issues requiring corrective action:
- [5/96]
- 6. Corrective Action Credit?
Brief summary of corrective actions: i l In response to the issues, the licensee. adopted corrective actions which included: A NL Operator was assigned to operate the fuel valve for the EDG and a procedure was changed to indicate the compensatory action. In the other cases the required 50.59 safety analyses have been performed, UFSARs are 4 being changed, and root cause determinations were initiated. Explain application of corrective action credit: I I PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
_ _ .__ _ __ _ ~ . . _ . . . _ . _ - ._ _ EMFGRCEMENT ACTION WORK 5EEET l Corrective action appears to be of appropriate scope.
- 7. r.=nriidate For Discretion? Yes Explain basis for discretion consideration: '
l Licensee's performance has been considered superior in the past.
- 8. Is A Predecisional: Enforcement Conference Necessary? Yes Why:
To determine adequacy of licensee % proposed long-term corrective actions regarding the 50.59 safety analysis program. If yes, should OE or OGC attend? [ Enter Yes or No): < Should conference be closed? [ Enter Yes or No):
- 9. Non-Routine Issues / Additional Information:
This issue should be discussed during a PEC along with the issues panelled the week of July 1. l I I PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE
.WITHOUT THE APPROVAL OF THE DIRECTOR, OE
. - - - - .- - ._ = -. . . .. . .-.
i ENFORCEMENT ACTIEN - 4- , wonxsazzT ! 10. 'This Action'is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: teles to provide) tif inconsistent, include:) Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Message:
Control must be maintained over the screening and performance of safety analyses (10 CFR 50.59).
- 12. Recommended Enforcement Action:
SL llI-Under current NUREG 1600 examples I.C.5 and I.C.7 under draft - examples I.C.10 and 1.C.ll. t
- 13. This Case Meets the Criteria for a Delegated Case tEics - Enter Yes or No)
- 14. Should This Action Be Sent to OE For Full Review? trics - Enter yes or wo)
If yes why:
- 15. Regional Counsel Review tEles to obtain)
No Legal Objecti.on Dated: J
- 16. Exempt from Timeliness: trics)
Basis for Exemption: Enforcement Coordinator: DATE: 1 I I i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE 1
. i 1
ENFORCEMENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION l l
- l O Problems' categorized at Severity Level I or II. l l
0 Case involves overexposure or release of radiological material in excess 1 of NkC requirements. ' O Case involves particularly poor licensee performance. l 0 Case (may) involve wi11 fulness. Information should be included to 1 address whether or not the region has had discussions with 01 regarding I the case, whether or not' the matter has been formally referred to 01, l and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, wi11 fulness, and/or management involvement should also be included. O current v'iolation is directly repetitive of an earlier violation. O Excessive duration of a problem resulted in a substantial increase in risk. O Licensee made a conscious decision to be in noncompliance in order to l obtain an economic benefit. l O Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) O Licensee's sustained performance has been particularly good. i O Discretion should be exercised by escalating or mitigating to ensure that the proposed civil penalty reflects the NRC's concern regarding the violation at issue and that it conveys the appropriate message to the j licensee. Explain- . PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Enclosure 3 REFERENCE DOCUMENT CHECKLIST [j NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: [] Licensee reports: [] Applicable Tech Specs along with bases: [] Applicable license conditions [] Applicable licensee procedures or extracts [ ]_ Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results [ ]- Extracts of pertinent FSAR or Updated FEAR sections for citations involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or' Confirmation of Action Letters [] Current SALP report summary and applicable report sections ['] Other miscellaneous documents (List): PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Safety Evaluations 10 CFR 50.59 Issues
.The inspectors reviewed and evaluated other 10 CFR 50.59 safety screenings and safety evaluations but the following four were identified as having problems.
..~ _
A. Safety Evaluation for Closing Manual Valve to EDG Fuel Supply The inspector reviewed the safety evaluation JPN-PSL-SENS-95-013, which was prepared to allow operation with a manual isolation valve closed in the 2B EDG fuel oil (FO) line from the 00ST to the day tanks. The configuration was proposed when a leak was determined to exist in the underground line between the two tanks. l The action was designed to minimize the amount of F0 released to the environment until the leak could be identified and corrected. As a compensatory measure, the licensee proposed dedicating an NLO l to the task of opening the closed valve in the event of an EDG i start. The licensee calculated that the EDG day tanks contained enough F0 to allow 126 minutes of EDG operation at full load before a transfer of F0 was required. The licensee then specified that the NLO would be required to epen %e valve within 20 minutes of an EDG start. Procedures were revised to include direction to open the valve on an EDG start, and administrative controls were put in place to ensure that the NLO would not be required to perform any other immediate response duties. Additionally, the licensee performed a response time test, placing the operator at the G-2 warehouse (as f ar away from the EDG as he could credibly be in the protected area) and requiring the NLO to proceed to the valve and open it. The NLO performed this task in approximately sevel minutes. In considering the issue, the licensee employed PRA techniques to estimate the increase in the risk nf the loss of the 2B3 bus due to a failure of either the operator to open the valve or a failure of the valve to be able to be opened. The licensee concluded that the increase in probability was approximately 6 percent. However, in considering 10 CFR 50.59 criteria, the licensee concluded that no increase in the probability of failure of a component important to safety was created by the proposed action. The inspector questioned the licensee on this issue. The licensee explained that a deterministic conclusion of no increased probability was reached when the existence of procedural guidance and heightened awareness was balanced against the approximate 6 percent increase in failure probability presented by the two new failure modes. In the context of regulatory compliance, the inspector noted that 10 CFR 50.59 was written in terms of absolute increases in the probabilities of failure represented by a proposed change. The inspector continued to question whether 10 CFR 50.59 criteria could ever be satisfied when new failure modes are imposed on a previously reviewed system (i.e whether added risk, once qualitatively established, could be completely mitigated). The inspector concluded that insufficient guidance existed from a PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i
1 regulatory perspective to.take immediate issue with the licensee's rationale...Further,.the inspector concluded that the licensee had taken prudent measures to ensure the continued operability of the 2B,EDG while minimizing the F0 leak's effect on the environment. The inspector referred tho question to NRR for resolution.
- ~
After consideration of the issue, the.hRC determinea tnat the actions taken by the licensee in this instance introduced two new failure modes to'the EDG system; failure.of the operator to unisolate the fuel oil line and failure of the manual isolation 1 valve to cycle. As a result, the NRC has concluded that the licer.see's actions necessarily increased the probability'of a
- failure of a component important to safety and, as.such,
, represented an Unreviewed Safety Question, as defined in 10 CFR , 50.59. Consequently, this action is identified.as a violation , (VIO 96 XX-ZZ, " Failure to Satisfy Requirements of 10 CFR 50.59"). i . B. Safety Evaluation for CEDMCS Enclosura i 3 .- l' On June 4,1996, a control room annunciator indicated that an undervoltage condition existed on the Control Eloment Drive Mechanism Control System (CEDMCS). Operations responded to the CEDMCS equipment and noted that the CEDMCS enclosure was i approximately 11 degrees warmer than normal. This enclosure is ! locattd in the cable spreading room on the 43 foot elevation of l the reactor auxiliary building.
-Following this event, an STA In-House Event Report and Condition
- Reports 96-1238, 96-1245 and 96-1325 were issued. Some of the following items with appropriate plant corrective action tracking
- number were identified by these reports:
} -
.CEDMCS enclosure and air conditioning units did not appear
? on the plant's controlled drawings. (STAR 951320) CEDMCS enclosure air conditioning units were not seismic qualified. Final design was in process to provide seismic restraints for the air condition units. (PM 96-06-208) As part of the action for Condition Report 96-1325, a 10 CFR 50.59 safety evaluation was performed on the CEDMCS enclosure. . The evaluation found that this air conditioned enclosure was erected in the early 1980's during the pre-operational testing phase. This testing found that the CEDMCS enclosure required an air conditioned environment to prevent overheating of the four CEDMCS rabinets. The licensee's review determined that the design of the enclosure was acceptable, except that the air conditioning units and one air conditioning duct presented a hazard to safety related equipment in a seismic event. Therefore, seismic supports and restraints were provided for the air conditioning units and duct prior to the unit's restart on June 13. The inspector reviewed the 10 CFR 50.59 evaluation provided for-the design and installation of the seismic restraints and PROPOSED ENFORCEMENT ACTION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
justification of the installation of the CEDMCS enclosure. This air conditioned enclosure was erected during the pre-operational test phase in the early 1980's to provide cooling for the CEA system. However, a 10 CFR 50.59 review was apparently not performed when the enclosure was originally erected. The CEDMCS
'N was described,in.the UFSAR but the cooling system and enciasure-for the CEDMCS were not aescribed in the UFSAR. This was identified as another example of URI 50-335, 389/96-04-09,
" Failure te Update UFSAR".
The failure to perform an evaluation as required by 10 CFR 50.59 prior to making a change to the plant as described by the UFSAR is identified as a second example of Violation 50-389/96-XX-YY,
" Failure to Satisfy the Requirements of 10 CFR 50.59." Also, the failure of the licensee to impose design control measures on the fabrication of the CEDMCS room and its air conditioning system is an additional example of VIO 96-XX-XX, " Failure to Adequately Manage Configuration Control".
C. Safety Evaluation for Inoperable Fire Pump During the Spring 1996 Unit I refueling outage, one of the two Unit 1 EDGs had been placed out of service to perform maintenance and modification work activities. Only one EDG was in service to provide power in the event of a loss of power event. To prevent a possible overload on the sinr.,le EDG unit, a number of breakers to various components were opened and the units 480V electrical busses were crosstied in accordance with OP l-0910024, Rev 6, "Crosstying/ Removal of 480V Buses." One of the components removed c from service was Fire Pump 18. The breaker to this fire pump was opened on 'iay 21, and this pump was removed from service and remained out of service on June 8, the end of this inspection period. AP 1800022, Rev 16, " Fire Protection Plan," Appendix A, Sections 2.2 and 2.3 required two fire pumps rated at a capacity of 2300 gpm to be operable at all times. Appendix A Section 4.1.A stated that with one of the two fire pumps inoperable, restore the inoperable equipment to service within seven days or provide an , alternate backup pump within the next 30 days. I Fire Pump 1B had been out of service for 18 days. The compensatory measure established for this pump being out of service was the installation of a portable gasoline engine drive pump rated at 750 gpm. This pump had been connected to take suction from the fire protection water storage tank for Fire Pump 1A. This alternate pump was not of the same capacity as one of the two required pumps and a justification was not provided to demonstrate that this pump was of adequate capacity to meet the maximum fire flow requirement for the safety related areas of the plant. The licensee initiated a CR to review this item. The licensee informed the inspector that the out of service pump could be restored to operability by restoring the existing open breaker to the closed position. Also, the 30 day time to provide PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE I
_ _ _ _ ~_ - . _ _ _ . _ _ _ __ i
)
, an alternate backupzpump had not been exceeded. This met the i requirements of AP 1800022 for one pump being inoperable. Resolution of the Condition Report (CR 96-1356) indicated that the i installation of the portable fire pump as the compensatory measure ! ? e- with ownpof-the permanently installed fire pumps out of service --. { violated the fire protection configuration as oescribed in the i UFSAR. An engineering evaluation should have been prepared to ; justify and document the temporary configuration. This is a third j 1 example of Violation 50-335, 389/96-XX-YY, " Failure to Satisfy the Requirements of 10 CFR 50.59". , D. Safety Evaluation for Refueling Equipment Set Points , Condition Report (CR) no.96-812 was issued by the licensee on the 1 safety evaluation number SEFJ-96-020, St Lucie Unit 1 Refueling , Equipment Underload and Overload Settings. The report stated that an engineering evaluation had been written to modify the overload
- and underload setpoints described in the FSAR without performing a 50.59 safety analysis / evaluation. These overload and underload l load cell setpoints provide a margin to account for resistance encountered while lifting or lowering fuel assemblies and prevent exceeding the fuel assembly and refueling equipment design loads.
l The licensee had obtained information from the vendor for use in 1 this Unit I refueling outage which would allow an increase in hoist interrupt from 10 percent to 200 pounds (approximately 18 percent for regular fuel assemblies). The original engineering analysis did not take into account that these changes in setpoint , values would affect the FSAR and thus the deviation report (CR) l 4 was written. ! St. Lucie Quality Instruction (QI) 2.0, Engineering . Evaluations, Rev. 1 dated January 31, 1996 provides general requirements and guidance for the development and processing of engineering evaluations. This procedure references QI 2.1, 10 CFR 50.59 i Screening / Evaluation, Rev. 1 dated March 30, 1996, which states in i 1 part that the screening process is designed to determine whether the activity requires a complete 10 CFR 50.59 by asking a series of four questions. One question, "Does the change represent a i change to procedures as described in the SAR7" should have been ; answered yes in the case of the original engineering analysis. The procedure also states that, " A positive response to any of i the first four ...... questions requires a 10 CFR 50.59 evaluation". The Facility Review Group (FRG), the site safety committee noted that a safety evaluation was not present with the requested procedure change and returned the procedure to the engineering group for correction and the CR was written to identify the problem. This violation of procedure which required a safety evaluation (50.59) be performed is a fourth example of Violation 96-XX-YY, !
" Failure to Satisfy the Requirements of 10 CFR 50.59".
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
_ _ ._ . _ _ _ . _ _ .. _ -_ .~ _ _ _ .__ t 3 10 CFR 50.59, " Changes, Tests and Experiments," (a)(1) stated, in part, that a licensee may make changes in the facility as described in the safety analysis report without prior Commission approval, unless the ; proposed change involves an unreviewed safety question. 10 CFR 50.59 ; (a)(2) stated, in part, that a proposed change shall be deemed to . involve an unreviewed safAy ouestiqqpif-the- probability of occurrence , of a malfunction of equipment important to safety previously evaluated in the safety analysis report may~be increased. (b)(1) stated, in part, the licensee shall maintain records of changes in the facility to the extent that these changes constitute changes in the facility as described in the safety analysis report or to the extent that they constitute changes in procedures as described in the safety analysis report. These records must include a written safety evaluation which ! provides the bases for the determination that the change does not ' involve an unreviewed safety question. The following four examples of a violation of these requirement were identified. Example 1-Con'.rary to the above, in July, 1995, the licensee made a change to the facility which involved an unreviewed safety question when ; the 2B Emergencj Diesel Generator fuel oil line from the fuel oil' tank to the day tank uas manually isolated to secure a through-wall fuel oil , leak. In taking the action, the licensee introduced two failure modes ' into the 2B Emergency Diesel Generator (operator failure to open a manual isolation valve during a valid demand and the failure of a manual l isolation valve to change state during an attempted opening) which necessarily increased the probability of occurrence of a malfunction of the Emergency Diesel Generator above that previously evaluated in the l safety evaluation report. j l Example 2-Contrary to the above, the licensee erected an enclosure around the Control Element Drive Mechanism Control System during some period around 1984 without performing a safety evaluation. This non-safety related structure was erected in a safety related cable spread room. Example 3-Contrary to the above, during the 1996 Unit I refueling outage ! with only one operable emergency diesel generator in service, the licensee removed one of the two 2,500 gpm fire pumps from service and installed a temporary 750 gpm fire pump arranged to take suction from fire protection water tank 18 and discharge into the fire protection water system via fire hydrant No. 12 without performing the required l safety evaluation. The fire protection water supply system is shared by l Units 1 and 2 and is described in UFSAR Appendix 9.5A, Section 3.0. Example 4-Contrary to the above, the licensee used an engineering
- evaluation to change the set points and procedures described in the FSAR l for operating the fuel hoist without performing a 10 CFR 50.59 safety 1 analysis / evaluation. l l
i PROPOSEC ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
e o ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE INFORMATION REOUIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL PREPARED BY: Mark S. Miller NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This information will be used by EICS to prepare the enforcement letter and Notice, as well as the transmittal memo to the Off1ce of Enforcement explaining and justifying the Region's proposed escalated enforcement action.)
- 1. Facili ty: St. Lucie Nuclear Plant Uni t (s) : 1 Docket Nos: 50-335 License Nos: DPR-67 Inspection Dates: December 4-31. 1994 Lead Inspector: Richard L. Preva tte
- 2. Check appropriate boxes:
[X] A Notice of Violation (wi thout " boil erpla te ") which includes the recommended severity level for the violation is enclosed. [] This Notice has been reviewed by the Branch Chief or Division Director and each violation includes the appropriate 1evel of specificity as ta how and when the requirement was violated. [] Copies of applicable Technical Specifications or license conditions ciced in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the vialation (s) {e.g.,
Supplement I.C.2) Supolement I.D.3
--THl$ DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR L
\_
ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE
- 4. What is the apparent root cause of the violation or problem?
Inadeavate analvsis of the desian of the NaOH addition lines to the Unit 1 Containment S_orav System.
- 5. State the message that should be given ta the 1icensee (and industry) through this enforcement action.
Desian reviews must be sufficientiv thorouah to orevent the l pmsibilitv of violatina desian basis assumotions.
- 6. Factual information related to the following civil penalty l escalation or mitigation factors (see attached matrix and 1 10 CFR Part 2, Appendix C, Section VI. B. 2. ) : l l
- a. IDENTIFICATION: (Who identified the violation? Wha t '
were the facts and circumstances related to the discavery of the violation? Was it self-disclosing? , a it identified as a result of a generic N's l notifica tion ?) ' The errant desian condition was self-disclosina when it l 1ed to the lif tina of a containment scrav suction relief l valve durina MOV testina with only 1 CS oumo operatina. 1 Ooerators were alerted to the condition by standina water. The desian feature in avestion involved a common line which effectively cross-connected the NaOH eductors, allowing the discharae from one CS_oumo to oressurize the suction of the other CS oum_o unless the second oump was o_oera tina.
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
The licensee performed a series of interim and final corrective actions. They included: e_ Validatina conclusions reached as to the reason for the rei.ief valve lif tina by alianina a LPSI pumo to
.Che CS discharae header and verifvina that the re11ef valve aaain lif ted (since LPSI discharae header oressure would be transmitted to the relief valve via the eductor line).
--THl$ DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
17 CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 2
ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE t Perfarmina an enaineerina evaluation to determine whether the CS suction lines had been overoressurized or damaged due to the event. While having been overoressized, the CS suction oiping was sufficiently overdesigned so as to oreclude damage. 2 Isolatina one eductor line (to eliminate the cross 1 connection) and entering the appropricte TS AS. l l t Performina a leak check of the CS suction lines ' under oumo discharge pressure head to verifv its ability to withstand such oressure (engineering had set the line's maximum oressure resistance at 250 psia) orior to aaquing the relief valves. t gn ging the relief valves 2 Preoaration of a PC/M to install obvsically jpdeoendent eductor lines. 2 Installation of the PC/M during the Uni t 1 outage. What were the immediate corrective actions taken upon discavery of the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? See above for corrective actions. The inspectors found the actions to be thorough and timelv. What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis? The licensee was proactive both in addressing the viola tion (root cause/ corrective action) and in assessing its potential consecuences. A number of studies of increasinq death and refinement were perfarmed befare the safety sianificance was established.
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer.
List paet vi01atians that may be related to the current viola tion (include specific requirement cited and the date issued) :
--THIS DOCUMENT CONTAINS PREDECIS.ONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 3
'O ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE There have been' no s1milar deslan-related violations in
} the last two vears. , Identify the applicable SALP category, the rating for ~ ~ this category and the overall rating for the last two SALP periods, as well as any trend indicated: SALP Cateaorv: Enaineerina
- The current ratinct for this cateaorv in 1 and was 1 in the oeriod orecedinc7 this. No downward trend has been a detected in the enaineerina area. ;
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities :
for the 1icensee to discaver the vialation sooner such
- as through normal surveillances, audi ts, OA activities, ,
- specific NRC or industry notification, or reports by i employees?
There is no evidence that 'the licensee would have had an ovoortunitv to identifv the condition bevond the reviews associated system. with the desian chanae that installed the
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this inspection? If there were, identify the number of examples and briefly ;
describe each one. ' pong l
- f. DURATION: How long did' the violation exist?
Since the installation of the NaOH system - 1978. i
-THl$ DOCUMENT CONTAINS PREDEclSIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 4
l l l l ESCALATED ENFORCEMENT PANEL OUESTIONNAIRF l l l ADDITIONAL COMMENTS / NOTES: See attached ccerots from insoection reoort discussians of thie iasue. Addi t.1onal1v. see the 1icensee*s LER and the sunolement thereto. which contains a l thorough discussion af safety sianificance and simalified svstam 1 diaarams to aid in visualizing the issue. l l From IR 94-22 l l
- f. ECCS System Leakage into Reactor Auxiliary Building (71707, 37551)
On September 20, water was found on the floor of the Reactor Auxiliary Building af ter differential pressure testing of the 1B Shutdown Cooling Heat Exchanger to 1B HPSI Pump Suction Isolation Valve (V3662) . This testing was accomplished to complete the requirements of NRC Generic 1 Letter 89-10. The licensee determined that the water had come out of the ECCS pump suction header relief valve SR 1A. The licensee
- s investigation of the event determined that 1B CS pump, which was used to provide the upstream pressure on valve V3662, also pressurized the ECCS suction piping through the NaOH system and the idle CS pump. A subsequent test was conducted with the same lineup using 1B LPSI pump to provide pressure and the same results were achieved. A piping system walkdown found that the train A and B CS recirculation piping that is used as the motive supply to the train A and B NaOH eductor for containment spray was tied together into a common header supplying both train A and B eductors. The pressure from the above test had resulted in pressurizing the ECCS suction piping of A train and actuating relief valve SR-07-1A. !
Af ter the above investigation, the licensee considered the 1 status of the core spray system questionable. They requested that engineering perform an evaluation to ; determine if the completed testing could have ' overpressurized the ECCS suction piping and if the safety l relief valve would lif t if CE or ECCS activated in response to an ESFAS. They also requested that engineering determine the impact on safety system performance if the relief valve lif ted during a postulated accident. The engineering analysis initial results were provided to the plant on October 23. They showed that the valve testing which resulted in actuation of the relief valve did
-THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 5 l l l l
. 1 1
j0 ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE l overpressurize the system, but did not result in any damage.
^
I
- The inspector reviewed this data and agreed with the 1icensees conclusions. -
l 1 The engineering review of the adverse effects of the relief \ valve, should it actuate under accident conditions, found
- that if one engineering safeguards pump was operating in each train the suction piping pressure would not reach a level to actuate the relief valves. However, it was found l that if a CSAS occurred concurrent with a LOOP and the l l failure of a EDG during a LOCA or MSLB then the running CS l i and NaOH system could pressurize the idle ECCS suction l piping and actuate the relief valve. This could result in a !
flow of approximately 100 gpm of RWT and/or containment sump water inta the auxi1iary building. This exceeds the FSAR' i Section 15.4.1. 7 maximum leakage of two liters per hour from i- ESF equipment external to containment. Based on the above analysis, the licensee isolated one train ) of the NaOH system and- entered the 72 hour AS of TS 3.6.2.2. 3 at 12:50 p.m. on September 23. They also issued instructions for operator actions to be taken 'to realign valves needed under accident conditions. The inspector reviewed the licensee's above actions and attended a plant i
; FRG meeting on this item. The actions taken at that time appeared to be timely and appropriate. , The licensee also directed engineering to develop both a l short term resolution that would permit continued operation a
until . the unit was shutdown for refueling on October 31, and a long term permanent ' design change. The short term y solutic,n proposed gagging the ECCS suction relief valves to
- prevent their inadvertent operation in case a train of ECCS equipment failed to actuate due to a loss of electrical l v power.
In order to accomplish this, the 1icensee reviewed design data and found that the relief valves had been installed to preclude overpressurizing this piping if leakage should i occur past a motor operated valve or the piping was not l isolated prior to initiating shutdown cooling. They ; additionally found that the system could withstand an internal pressure of 250 psig which is well above the pressure that the system would be exposed to under the above scenario. Af ter receipt of the above evaluation the licensee performed a pressure test and leak inspection to verify that the THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION-- IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 6
1 O s ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE system could withstand the pressures it could experience under the postulated conditions. The tests achieved satisfactory results and the relief valves were gagged and the system was declared operable on October 26 at 5:54 a.m. j Engineering reviewed the options available for a permanent l fix and decided on October 27 that the piping would be modifled to provide independent flow paths from train A and j B containment spray system to the NAOH eductors. They are currently developing a modification package to accomplish this work during the current refueling outage. The inspector reviewed this issue, when identified, with l opera tions, engineering support and plant management. He j attended management and safety review meetings where interim : and long term solutions were developed. A detailed review j of the proposed actions and engineering evaluations found 1 the licensees actions to be timely, conservative and appropriate for the existing conditions. The licensee long term fix also appears to be the correct way to address this item. The inspector noted strong management involvement in developing the interim and long term fixes. Engineering support on this issue was very responsive at the site and corporate offices. The licensee submitted LER 1-94-06 on this item on November 2, 1994. The inspector is currently reviewing this submi ttal . Proposed for IR 94-25 (Closed) LER 335/94-06, Containment Integrity Outside of FSAR Assumption Under Limited Circumstances Due to Design Error. This LER was submitted November 2. The inspector reviewed and evaluated the licensee's initial corrective actions (LER items 1 through 7) in IR 335,389/94-22. At that time the licensee was evaluating the long term solution to the problem (preparing a modification to be installed during the 1994 refueling outage), performing an assessment of the safety consequences and implications of the design deficiency, and preparing to share the 1essons 1 earned with industry.
--THl$ DOCUMENT CONTAINS PREDECISIONAL INFORMATION-- ,
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE ] APPROVAL OF THE REGIONAL ADMINISTRATOR 7 " l l
l ESCALATED ENFORCEMENT PANEL _ QUESTIONNAIRE Additional piping to physically separate the common NaOH header was installed during the Unit 1 refueling outage. The inspector reviewed the design change package and performed several system walkdowns to observe in-process work. The inspector noted that several problems were experienced while welding the modified piping. OC believed tha t the problems occurred due to residual moisture in the
-lines and inadequate purge gas flow. The inspector verifled that all of the above problems were reworked and corrected and the modification was completed and satisfactorily tested prior to Unit 1 restart.
JPN engineering performed an assessment of the safety , consequences and implications of the design deficiency. This assessment JPN-PSL-GENP-94-079 considered three cases of a large break LOCA and one case for a small break LOCA (2 ") . In the large break LOCA cases, a path to vent an idle ECCS loop to the RCS was identified. Under the assumed conditions of a '1arge break LOCA coincident with a 1oss of affsite power and an EDG fai1uzu., the pressure which would result in the common ECCS suction line of the idle train (due to the eductor cross connection) was found to transmit through the idle LPSI pump into the RCS. This path offered less resistance to flow than the relief valves in question. The vent path would be available following the blowdown phase of the accident. In the small break LOCA case operator action would be required to change system alignments or activate equipment to prevent excess leaks from the relief valves into the ECCS equipment rooms. Since this action is addressed in EOPS it was also considered to be a success path. The above \ evaluation was discussed in detail in LER 335/94-06 ) supplement 1 submitted by the 1icensee on December 2, 1994. The inspector reviewed the LER and supplement, the engineering evaluation, and the LPSI system pressurization response due to common NaOH injection crosstie (calculation (PSL-IFuM-94-19)) to verify that the relief valves would not lift during a large break LOCA. The inspector also attended i several management and FRG meetings where this issue was l discussed in detail. The inspector concluded that, al thouy an error was made in the design and installation of this system in 1978, the licensee's engineering evaluation ; clearly demonstrated that it represented only minor safety significance under the condi tions of a LOCA, a 1oss of offsite power and the failure of one EDG. Under those condicions, if operators fol1 owed the guidance of the EOP,
--THIS DOCLHENT CONTAINS PREDECISIONAL INFORMATION '
IT CAN WOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 8
l d ESCALATED ENFORCEMENT PANEL OUESTIONNAIRE l i they would be able to identify and resolve leakage into an ECCS pump room that would occur. l i This item was identified -by the licensee. Upon identification their corrective ~ action was thorough, timely, and complete. The licensee failure to verify the adequacy ? of the design -of the NaOH system represents a violation of l 10 CFR 50 Appendix B Criterion III. This violation will not i be cited because the licensee's, efforts in identifying and , i correcting the violation meet the criteria specified in i Section VII.B of the NRC enforcement policy. It will be identified as NCV 50-335/94 , Inadequate Design l l Control. The inspector also verified that the licensee had informed the responsible AE of this event and shared this information with other utilities through the INPO Nuclear Network. I 1 i i I j l 4 I
, -THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE I APPROVAL OF THE REGIONAL ADMINISTRATOR 9 l l i
. . . - .--- . - - - _ - - ~ - - . -- - . . -
. i e l e
a ESCALATION AND MITIGATION FACTORS (57 FR 5791, February 18, 1992) IDENTIFICATION CORRECTIVE LICENSEE PRIOR IRJLTIPLE DURATION ACTION PERFORMANCE OPPORTUNITY TO OCCURRENCES ; ! IDENTIFY
+/ 50% +/- 50% +/ 100% + 100% + 100% + 100%
! Licensee Timeliness of Current Licensee should Multiple Used for j identified (M) corrective violation is an have identified examples of significant i 2 (To be applied action (M) isolated violation violation regulatory even if LDid NRC have failure that is sooner as a identified message to licensee could to intervene to inconsistent result of prior during licensee. (E) 4 have accomplish with licensee's opportunities inspection identified the satisfactory good such as audits (only for SL 1, violation short term or performance (M) (E) II or !!! sooner) remediai action violations) (E) l (E)] i NRC identified Promptly Violatfor,is opportunities OTHER CONSIDERATIONS ; (E) developed reflective of available to . I schedule for licensee's poor discover 1. Legal aspects and potential , d long term or declining violation such litigation risks j a corrective performance (E) as through ' 3 action (M) prior 2. Negligence, careless dis-notification regard, willfulness and (E) management involvement a Self- Degree of Prior Esse of earlier 3. Economic, personal or disclosing licensee performance and discovery (E) corporate gain l (M 25% if initiative (M) effectiveness , , there was [To develop of previous 4. Any other regulatory frame- 1 initiative to corrective corrective work factors that need to be ) i identify root actions and action for considered: pending action ' cause) root cause) similar with regard to licensing, 1 violations commission meeting, or press ! conference. ' Licensee Adequacy of the SALP - Period of time identified as root cause Consider between 5. What is the intended message a result of analysis for SALP 1 - (M) violation and for the licensee and the generic the violation SALP 2 - (0) notification industry? .; notification (M) SALP 3 - (E) received by (M) licensee (E) .......... NOTES" ---- "- Comprehensive Prior Similarity corrective enforcement between the action to history violation and prevent including notification occurrence of escalated and (E) similar non-escalated violation (M) enforcement Inunediate Level of corrective management action not review the takon to notification restore safety received (E) and comptiance (E) SAFETY $1GNIFICANCE: In determining the safety significance of a violation in conjunction with the enforcement process, the evaluation should consider the technical safety significance of the violation as well as the regulatory significance. Consideration should be given to the matter as a whole in light of the circunstances surrounding the violation. There may be cases in which the technical safety significance of the matter is low while the process control failure (s) may be significant, and, therefore, the severity level determination should be based more on the process control failure (s) than on the technical safety issue. The following factors should also be considered: 1) Did the violation actually or potentially impact public health and safety? 2) What was the root cause of the violation?
- 3) is the violation an isolated incident or is it indicative of a programmatic breakdown? 4) Was management aware of or involved in the vlotation? 5) Did the violation involve willfulness?
j , 0-ESCALATED ENFORCEMENT e PANEL QUESTIONNAIRE f INFORMATION REQUIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL ! PREPARED BY: R. Prevatte 1 NOTE: The Section Chief is responsible for. preparation of this questionnaire
- and its distribution to attendees prior to an Enforcement Panel. (This i information niil be used by EICS to prepare the enforcement letter and Notice, i as well as the transmittal memo to the Office cf Enforcement explaining and j justifying the Region's proposed escalated enforcement action.)
- l 1. Facility: St. Lucie Unit (s): 1 4
L l l Docket Nos: 50-335 ' License Nos: DPR-67 p ! Inspection Dates:- July 30 - September 16. 1995 1 Lead Inspector: Richard L. Prevatte i 2. Check appropriate boxes:
- [X] A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is enclosed.
1 [] This Notice has been reviewed by the Branch Chief or Division j Director and each violation includes the appropriate level of
- specificity as to how and when the requirement was violated.
l- [] Copies of applicable Technical Specifications or license ! conditions cited in the Notice are enclosed. 4 l 3. Identify the reference to the Enforcement Policy Supplement (s) that best ! fits the violation (s) (e.g., Supplement I.C.2) ' , I.C.7 I{' 4. What is the apparent root cause of the violation or problem 7 4 Failure to follow orocedures (multiple examoses - 8) I 5. State the message that should be given to the licensee (and industry) j through this enforcement action. i Procedures must be used and followed. If errors exist in the orocedures y j that orevent followino them. the errors must be corrected, g
i. i'
- 6. Factual information related to the following civil penalty escalation or !
' mitigation factors (see attached matrix and l 4 10 CFR Part 2, Appendix C, Section VI.B.2.): I
! a. IDENTIFICATION: (Who identified the violation? What were the ! facts and circumstances related to the discovery of the violation? j Was it self-disclosing? Was it identified as a result of a
- generic notification?)
l 4 examples identified by NRC. 2 examples by licensee. and 2 were self-identifyina.
- b. CORRECTIVE ACTION: Although we expect to learn more information i
regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview. i Some procedure chanaes made. Dersonnel disciolined. and licensee
- . strivina to imorove standards and nerformance.
j ' What were the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-ters t-corrective action and the timeliness of corrective-actions? f Promot action taken each event. s j What was the degree of licensee initiative to address the a violation and the adequacy of root cause analysis? i , This is a lona term action oroblem. 2 l c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer. List past violations that may be related to the current violation (include specific requirement cited and the date issued): NCV 95-07. Loss SDC - incorrect valve manioulation by operator. VIO 94-22-02. Lookeepina errors. Identify the applicable SALP category, the rating for this category and the overall rating for the last two SALP periods, as well as any trend indicated: i Operations 1 Recent events indicate neaative trend. j
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities for the licensee to discover the violation sooner such as through normal surveillances, audits, QA activities, specific 1RC or industry notification, or reports by employees?
.N_L. -
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this inspection? If there were, identify the number of examples and briefly describe each one.
8 examoles. see attached violations
- f. DURATION: How long did the violation exist?
8.lh P G s
ADDITIONAL COMMENTS / NOTES: b i 1 I i i 1 1
i e ESCALATION AND MITIGATION FACT 0as (57 Fa $791, February 18, 1992)
! IDENTIFICATI0Il CNEECTIVE LIWuME PRIM IRA.TIPLE DiaATIM j ACTIM PERFtWIANCE EPPORTlallTT TO arr m osurve 1 IDENTIFY I 1
- +/ 50% e/ SOE +/ 100s + 100E + 1002 + 1005 l 4
Liconsee Time 1iness of Current Liconsee eheutd MuttIple used for l i identified (M) corrective violation is an ' have identified examples of significant (To be applied action (M) isolated vlotation violation regulatory i even if gold NRC have failure that is sooner as a identified message to 1 Licensee could to intervene to inconsistent result of prior diaring Licensee. (E) i have acceeptish with licensee's opporttmities inspection i identified the satisfactory good such as audits (only for $L I, l vlotetten short term or performance (M) (E) II or III t sooner) remedial action violations) (E) ] (E)) l NAC identified Proeptly violation is opportunities OfifER 1lDil11DERATICIls (E) developed reflective of avaltable to i schedule for licensee's poor discover 1. Legal aspects-and potentist Long term or declining vlotation such titigation risks ! corrective performance (E) as through _
- action (M) prior 2. Neglisence, cereless dis-j notification record, wittfulness.and
- (E) senegement involvement 3
self- Degree of Prior Esse of earlier 3. Economic, personst'or ] disclosing licensee performance and discovery (E) corporate gain
- (M 25% if initiative (M) effectiveness j there was (To develop of previous 4. Any other regulatory frame , ;
initiative to corrective corrective work factors'that.nood to be identify root' actions and action for considered pending.actlen 1 j cause) root cause) simiter with regard to Ifconsing, . ; vietatIans cassission meeting, or . press . ; conference. 4 Licensee Adequacy of the l SALP - Period of time i , identified as root cause Considers between 5. What is the intended message j a result of analysis for SALP 1 - (M) violation and for the (icensee and the i generic I i the vlotation SALP 2 - (0) notification indJetry? ' j notification (M) SALP 3 - (E) received by M) tleensee (E) 1
.......... If0TES +- +--**
Comprehensive Prior Similarity ) corrective enforcement between the
- action to history violation and
- prevent including notification occurrence of escalated and (E) similar non escalated violation (M) enforcement 1
i Issuediate Level of i corrective man 6gement action not review the
, taken to notification j restore safety received (E) and compliance (E)
{ mmmm { SAFETY SIGNIFICANCE ' In determining the safety significence of a violetten in conjmetion with the enforcement process, the evaluation should consider the technical safety significence of the vlotation as wett as the regulatory significance. Consideretton should be given to the matter as a whole in light of the ciretanstances surromding the violation. There may be cases in which the technical safety significance of the matter is low while the process control felture(s) may be signifteent, and, therefore, the severity level determination should be based more on the process control f alture(s) than on the technicet safety issue. The following factors should etso be considered: 1) Did the violation , actually or potentistly 1spect public heetth and safety? 2) What was the root cause of the vlotation? l 3) is the vlotetton en isolated incident or is it indicative of a programunetic breekdown? 4) Was a management aware of or involved in the violation? 5) Did the violation involve wittfulness? i i 4 L _ _ _ _
. - ~ . --.- . - -. - - - . . - - . - - - . - _ _ _
. l
\
Prooosed Violation A l l i Technical Specification 6.8.1.a required that written procedures be
- established, implemented, and maintained covering the activities
! ) recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February 1978. Appendix A, paragraph 1.d includes administrative procedures for ;
- procedural adherence. Procedure QI 5-PR/PSL-1, Rev 62, " Preparation, '
4 Revision, Review / Approval .of Procedures," Section 5.13.2, stated that all procedures shall be strictly adhered to. J
. Contrary to the above, the following examples of procedural l i- noncompliance were identified:
l ,
, 1. OP 1-0030127, Rev 68, " Reactor Plant Cooldown - Hot Standby to l
Cold Shutdown," required, in part, that operators block Main Steam Isolation System (MSIS) actuation when block permissive i g/ annunciations were. received. ONOP l-0030131, Rev 60, . " Plant Annunciator Summary,". required that, upon valid receipt of 3 annunciators Q-18 and Q-20, operators immediately block MSIS channels A and B, respectively. j Contrary to the above, on August 2, 1995, during a cooldown of St. ' 4 Lucie Unit 1, operators failed to establish the required MSIS l blocks, resulting in A and B channel MSIS actuations. i r 4 j2- OP l-0120020, Rev 72, " Filling and Venting the RCS," precaution 4.2, required that Reactor Coolant System (RCS) venting, described in the procedure, not be attempted if RCS temperature was above 1 200*F. 1
~
l Contrary to the above, on August 2, 1995, Reactor Coolant Pump { (RCP) seal venting, performed in an attempt to correct seal j i t package leakage in the IA2 RCP in accordance with Appendix E cf j l V ' the subject procedure, was performed while RCS temperature was hf g approximately 370*F. As a result, design temperatures of RCP seal components were approached or exceeded. 1 ~ s 3. OP 1-0120020, Rev 72, " Filling and Venting the RCS," Appendix E, (v )l " Restaging Reactor Coolant Pump Seals," required the use of RCP j seal injection while restaging was attempted.
- Contrary to the above, on August 2, 1995, restaging of the IA2 RCP
! seal package was attempted without seal injection aligned to the seal package. As a result, design temperatures of RCP seal ; components were approached or exceeded.
- ~0P l-0010123, Rev 99, " Administrative Controls of Valves, Locks, j and Switches," step 8.1.6, required, in part, that all valve position deviations be documented in the Valve Switch Deviation h' Log.
1
; Contrary to the above, on or about August 1, 1995, HCV-25-1 j through 7 were repositioned and left in the closed position i
h
~
i
- without the required entries being made in the Valve Switch
. Deviation Log. The valves' positions exacerbated a loss of RCS
- l. inventory.
! i 5. OP 0010129, Rev 24, " Equipment Out-of-Service," step 3.2, required
- that all-equipment required by Technical Specifications be logged kr\f in the Equipment Out-of-Service Log when determined to be inoperable.
Contrary to the above, inspections performed on September 1 and 2, !. 1995, identified inoperable equipment, required by Technical
- Specifications, which had not been placed in the Equipment Out-of-l Service Log. Specifically, Unit 1 Containment Purge Valve FCV 4 and the IB Emergency Diesel Generator Fuel Oil Transfer Pump
- were both inoperable without being entered into the Equipment Out-4 s
of-Service Log. v
,/
/ 6. OP l-0410022, Rev 22, " Shutdown Cooling," step 8.3.7, required
! / that V3652, the B Shutdowr Cooling (SDC) hot leg suction isolation j / valve, be locked open while. placing the B SDC loop in service.
- i e
Contrary to the above, on August 29, a control room operator i failed to place V36L2 in a locked open condition while placing the l ' f B SDC loop in service. As a result, the IB Low Pressure Safety ' l Injection Pump was operated with its suction line isolated. e l I 4pp f7 j QI 16-PR/PSL-2, Rev 1, "St. Lucie Action Report (STAR) Program," required that STARS be initiated for Quality Assurance audit j 7 findings and independent technical review recommendations. l / Contrary to the above, a STAR was not generated when a Quality ; j Assurance review of an inadvertent Unit I containment spraydown, i documented in interoffice correspondence. JQQ-95-143, identified
- the practice of pre-lubricating FCV-07-1A, Containment Spray i header A flow control valve, when performing valve stroke time l testing.
s
- 8. ADM-08.02, Rev 7, " Conduct of Maintenance," Appendix 5, step 5, required that procedures be present during work and that
,- individual steps be initialed once performed.
g,p Contrary to the above, inspection of work in progress revealed
/ that individual steps were not initialed upon completion for work conducted in accordance with Plant Change / Modification 11-195.
This is a Severity-Level III violation (Supplement I).
5 i
- EXCERPTS FRON IR 95-15 l 3) RCP Seal Failure '
- Background St. Lucie employed Byron-Jackson RCPs and seal packages. The packages consisted of 3 primary seals and a fourth vapor seal.
The primary seals acted to break down RCS pressure in 3 equal stages of approximately 750 psid. The seal stages segregated the seal package into 4 cavities, the lower (below the lower seal), the middle (between the lower and middle seals), the upper (between the middle and upper seals), and the controlled bleedoff (between the upper and vapor seals). Each seal was rated for full RCS pressure. The pressure breakdown process resulted in a controlled bleedoff flow to the VCT of approximately I gpm per pump. Seal injection into the lower seal cavity was possible via the CVCS system, however, the licensee discontinued routine use of seal injection in 1993 (via safety evaluation JPN-PSL-SENJ-93-001) following indications that the cooler injection water led to damage of RCP shafts. The seals were cooled and lubricated by controlled bleedoff flow which was cooled by a combination of the thermal barrier heat exchanger (below the seal package) and a seal water heat exchanger (which cooled flow rising from the RCP casing driven by an auxiliary impeller affixed to the pump shaft).- Seal Failure l On August 2, while performing a Unit I heatup following Hurricane Erin, operators noted that the middle seal cavity of the IA2 RCP indicated a pressure which approximated RCS pressure, indicating a failure of the lower seal of the package. Operators subsequently entered ONOP l-0120034 Rev 1 34, " Reactor Coolant Pump," which required, upon ; identification of a failed seal, that seal parameter data be recorded every 30 minutes to ensure that additional seal stages were not degrading. i
.Throughout the day, the licensee considered the option of
" restaging" the seal package. The process involved opening vents associated with each seal cavity in an effort to !
increase the differential pressure across each seal stage which, in principle, would force moving and stationary seal faces together more tightly, thus reestablishing the seal. The evolution was described in OP 1-0120020, Rev 7P., " Filling and Venting the RCS," Appendix E, " Restaging Reactor Coolant Pump Seals." According to various personnel in the licensee's Operations organization, the process had been successfully applied several times in the past. The licensee opted to perform the procedure, and informed the inspector of their intentions.
i ! The inspector was not familiar with the process; however, in l discussions with the licensee, the inspector was informed that I the process had been performed satisfactorily in the past, i that a procedure existed for the process, and that experienced ANPSs, who had performed the procedure in the past, were being assigned to the task. ' l l At 5:17 p.m. on the same day, the licensee began the restaging process. Plant conditions at the time were Mode 3,1450 psia, 370*F, with RCPs in operation. Per the governing procedure,.
- the controlled bleadoff cavity was vented, followed by the
- upper and middle cavities.. At this point, flow out the vents was expected to decrease as the lower seal stage restaged; i
however, flow did not diminish and, after approximately 1 l minute, black material was noted to be in suspension in the
- vented reactor coolant from the middle cavity. Additionally, i the water . temperature was noted to increase rapidly.
- Operators closed the middle cavity vent valve and noted that, almost immediately, black, hot, water issued from the upper i- seal cavity vent, indicating a middle seal failure. Operators i immediately closed the vent valves associated with the upper i seal cavity and the controlled bleedoff. cavity.
I At 5:50 p.m., control room differential pressure indications !._ were received which confirmed that both the lower and middle seal stages had failed. Controlled bleadoff flow increased to
- greater than 3.5 gpm., which indicated degradation of the
. -upper seal. At 6:10 p.m., a cooldown and depressurization of j the unit commenced. At 6:40 p.m., the IA2 RCP was secured and ! lower seal cavity temperatures were noted to increase to 300*F , due to the increased leak rate through the seal package and I
; the lack of auxiliary impeller-driven cooling (as a result of j securing the pump).
A. MSIS Actuation As the cooldown proceeded, SG pressure decreased and, at approximately 700 psig, annunciators Q-18 and Q-20, "MSIS Actuation Channels A/B Block Permissive," illuminated. These were expected alarms, as cooldowns naturally result in SG pressure decreases below the MSIS setpoint. MSIS block keys were provided for this eventuality to prevent MSIS actuations under non-accident related conditions of low SG pressure. The desk RCO, who was performing cooldown-related duties at the subject area of the control panels, acknowledged the annunciators and later reported observing that the MSIVs and MFIVs were in their post-MSIS positions as a function of the cooldown. Consequently, the RCO elected not to insert the MSIS block and returned to VCT degassing operations. The RC0 was then questioned by an 2 i
l l STA as to the failure to block the MSIS. The RCO
- responded that, as the MSIVs and MFIVs were in their post-trip positions, the actuation would not present a problem. The board RCO (the second of the two RCOs performing the cocidown) became involved and directed that the MSIS be blocked.' Before the keys could be inserted to block the signals, SG pressure fell below the actuation setpoint and an MSIS was received. The signal was later blocked and reset.
The inspector reviewed HPES'95-07, Rev 2, the licensee's review of the event. In it, the licensee detemined that, in "Sunnary of Factors that Influenced Human Performance," the ever.t was the result of a lack of knowledge on the part of the desk RCO_that an MSIS was ' reportable to the NRC whether or not components changed state. Under " Summary of Causes," the licensee cited the following causal factors:
- Training / Qualification:
'The licensee determined that training had ~not educated operators as to the reportable nature of ESF actuations, whether or not components changed state.
- Supervisory Methods - Progress / Status of Task not -
Adequately Tracked: The licensee determined that the ANPS and NPS were too involved in the diagnosis of the RCP seal failures and were not observing the overall cooldown in progress at the time.
- Work Practices -
Pertinent Information not Transmitted: The licensee determined that the desk RCO did not announce to the rest of the control room that the annunciators had been received; thus, ANPS/NPS involvement to establish the MSIS block was not obtained.
- Work Practices -
Document Use Practices - Documents not Followed Correctly: The licensee determined that OP l-0030127, Rev 68, " Reactor Plant Cooldown - Hot Standby to Cold Shutdown," contained a step requiring the operator to block the MSIS when the permissive was received; however, the step was contained further into the procedure than the operator had proceeded. Additionally, the licensee determined that the operator had failed to refer to the annunciator response procedure, which directed that the block keys be inserted. 3
i. l 1 i
- The licensee's proposed corrective actions for this ,
l event included: l
- Revising operator training to include "the
' necessity. to block ESFAS and other reportable actuations when they alarm...The plant's " operating philosophy of keeping Licensee Event . Reports to a minimum should also be included and l stressed.-" l '
- Including - the event in Licensed Operator i Requalification Training.
S
- Emphasizing that control room management should maintain a' " big picture" yiew of plant i evolutions, that formal crew communications i
should be employed, and that procedures are i followed. 4 l The inspector concluded that the licensee's
- investigation was weak in that:
e The operator's knowledge- of procedural l j requirements prior to the event was not reported l l (i.e. did the operator know that the OP l-0030127 i ! required that the MSIS be blocked?). j The conclusion that the operator's lack of knowledge of the reportability of the MSIS actuation was a principle contributor to his actions appaarad to place more importance on avoiding an administrative / visibility burden (i.e. reporting actuations to the NRC) than it did on knowledge of, and adherence to, procedural requirements. The inspector discussed the subject report with the licensee. Operations management stated that the ; operator in question reported being confused at the time I and that it was their expectation that, under such circumstances, operators would refer to the annunciator response procedures provided for each annunciator panel. Management further stated that it was not their expectation that RCOs would be familiar with NRC reporting requirements (this knowledge was said to be the responsibility of ANPS/NPSs .and STAS) and that operator actions should be based upon procedure requirements, as opposed to reportability. The inspector reviewed OP l-0030127 and found that step 8.21 directed that "At 700 psia S/G pressure, Annunciators Q-18 and Q-20, MSIS Actuation Channels A/B 4
l. i 1 }o- . Block Permissive, will alarm. Block MSIS by placing l MSIS block key switch to BLOCK position." Additionally, i
- DNOP l-0030131, Rev 60, " Plant Annunciator . Summary,"
specified that, upon valid receipt of annunciators Q-18 and Q-20, operators were to immediately block MSIS channels A and B, respectively. The inspector concluded ' that the failure of the Desk RCO to perform step 8.21 of i OP l-0030127 constituted the first example of a violation (VIO 335/95-15-01, " Failure to Follow
- Procedures," Example 1). .
1 ! Following the MSIS, the cooldown was temporarily suspended. j At approximately 8:18 p.m., an annunciator was received indicating that reactor cavity leakage exceeded 1 gpm. Operators verified that control room instruments indicated an increased leak rate from approximately .25 gpm to approximately 2 gpm. The leakage was identified as being related to the IA2 RCP vapor barrier. Operators entered ONOP l-0120031, Rev 23, " Excessive Reactor Coolant System Leakage," at 8:24 p.m. At 8:44 p.m., safety function status checks were completed satisfactorily. At 9:25 p.m., the licensee declared an unusual Event based upon occurrences that warrant increased awareness, specifically, due to concerns over further RCP seal degradation. At 6:30 a.m. on August 3, the Unusual Event was terminated based upon the reduction in RCS leakage through the IA2 RCP seal (due to depressurization) and on stability of plant conditions. The licensee performed a cooldown/depressurization of Unit I and replaced the subject seal package. The failed package was then disassembled. in an attempt to determine the root cause for the failures. At the close of the inspection period, the licensee had.not concluded its root cause investigation. The inspector discussed the effort with the licensee. The most probable root causes for the noted conditions were described as follows:
- The most probable root cause for the indicated failure of the lower seal was destaging.- Upon restaging, the carbon face of the lower seal was believed to have been forced, rapidly, against its mating seal face, resulting in fracture.
. The most probable cause for the middle seal failure and degradation of the remaining seals was stated to be a reduction in cooling and lubricating flow though the seal as a result of the venting of the seal cavities.
The subsequent torque, imposed due to pump rotation without lubrication, fractured the middle seal rotating ; face. Following the failure of the IA2 RCP seal package, the PGM 5 l I
t 1 initiated STAR 950849 to perform a self-assessment of the 1 l ' decision making process that led to the restaging of the seal. The conclusions reached in the self-assessment were that the !- one-on-one nature of the decision making process precluded a ! " synergistic environment." The study went on to state that, j while several individuals expressed concern.over the prospects
- far success, no specific technical issue was raised. The l licensee determined that the existing Nuclear Policy 105
- process, which required multidiciplinary review of proposed j abnormal activities, should be expanded such that it is 3 employed when questions of procedure applicability are raised.
e The inspector reviewed available information regarding RCP seals and restaging. The folloWing was noted: l . OP 1-0120020, Rev 72, " Filling and Venting the RCS," i contained, in the base procedure, precaution 4.2 which stated."Do not attempt to vent if the RCS temperature is
- above 200*F." Initial conditions specified in the base i procedure were consistent with the Cold Shutdown mode of j operation.
6 i . OP 1-0120020, Rev 72, " Filling and Venting the RCS," l Appendix E, " Restaging Reactor Coolant Pump < Seals," i included only two statements that could be construed as j- initial conditions or precautions. One was in the fors; , of a note and the other in the form of a caution. The
- note stated " Ensure seal injection is aligned and in
".- service." The caution stated "If RCS is greater than j '200*F, Then use caution when venting." FSAR section 5.5.5.2 stated that the vapor seal was designed to withstand RCS operating pressure when the RCPs were idle.
. The restaging process described in Appendix E to OP 1-0120020 was substantially the same as the seal package venting procedure described in the vendor technical manual for the RCP. However, the venting procedure in the technical manual directed that the venting be performed at approximately 200 psi with an idle pump.
- Safety Evaluation JPN-PSL-SENJ-93-001, Rev 1, " Deletion of RCP Seal Injection," included, by reference, FPL letter L-81-107 to the NRC reporting test results for i RCP seals in postulated station blackout conditions. ;
The results of the tests were that, under simulated Hot Standby conditions, a maximum of 16.1 gph was recorded after 50 hours without cooling water flow to the seal package.
. The vendor recommended a maximum seal package 6 i i
J temperature of 250*F based upon the rubber coarponents in the seal package. Safety evaluation JPN-PSL-SENJ-93-001 provided analyses to increase the temperature limit to 300*F.
- The licensee produced a Byron-Jackson letter, dated November 16, 1990, which reported 'a review of St. !
Lucie's proposed restaging process. The letter stated that the proposed process was acceptable. The letter also stated that application of the process should consider initial seal. condition and age in determining whether to apply the process. The inspector concluded that the licensee had reason to believe that restaging the IA2 RCP seal package would correct i the identified condition. Vendor information and knowledge of previous successful restagings tended to support the evolution. However, the inspector found that the procedure l appendix whicii directed the evolution did not require initial l conditions sufficient to ensure that seal package temperature limitations would be observed. In fact, the " Caution" statement of the Appendix (advising caution if RCS temperature exceeded 200*F) ran counter to precaution. 4.2 of the base procedure (precluding venting if RCS temperature exceeded 200'F) . Absent any modifying information in Appendix E, the l inspector concluded that the initial conditions specified in l the base procedure applied to the procedure and its i appendices. Consequently, the failure of the licensee to adhere to the initial conditions specified in OP l-0120020 is an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 2). The inspector noted that control room logs did not reflect the alignment of seal injection, while the note of Appendix E of OP l-0120020 required seal injection. When questioned, the licensee stated that seal injection was not aligned due to concerns for the affect it might have on the RCP shaft. When , asked why a TC had not been made to the Appendix, the licensee . had no explanation. The licensee's failure to align seal ! injection to the IA2 RCP prior to restaging the pump's seal is .
-an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 3).
The inspector reviewed ONOP l-0120034, Rev 34, " Reactor Coolant Pump," and found that, while actions were described for the failure of one RCP seal (30 minute readings to ensure degradation is not occurring - step 7.2.8.C), and more than one RCP seal'(unit shutdown, secure RCP when TCBs open - step 7.2.8.D), no actions were specified for the instance when '3 seals had failed. As stated above, the fourth, vapor, seal was only designed to contain system pressure when an RCP is idle. The failure of ONOP 1-0120034 to direct the securing of 7 6
i ^ an RCP when 3 seals have failed was found to be in contradiction to the design parameters of the RCP. The I inspector brought this to the attention of the licensee. The licensee reviewed the issue and stated that PCRs would be prepared for the RCP off-normal procedures for each unit, adding a requirement to trip the unit and secure the affected RCP should third stage seal failure occur. 4 In conclusion, the inspector found that the activities relating to the failure of the lower seal of the IA2 RCP were poorly considered in that the restaging process was applied in
- inappropriate plant conditions. The ' failure to establish proper initial conditions for the restaging was found to i exacerbate the seal's already degraded condition. The inspector further concluded that two examples of procedural noncompliance were associated with the seal restaging effort and that one example of procedural noncompliance was associated with the MSIS actuation. The licensee's evaluation
! of the MSIS actuation was found to be inappropriately focused on event reportability, as opposed' to procedure compliance. The licensee's self-assessment of the decision making process that led to the restaging of the IA2 RCP was found to be , commendable. OP 1-0120034 was found to include i inconsistencies between the base procedure limitations and those found in Appendix E of the same procedure. A weakness was identified in ONOP 1-0120034, in that design limits of the I i RCP seal package vapor seal were not properly incorporated i into the procedure.
- 4) Reduced Inventory for RCP Seal Replacements On August 5,, Unit I entered a reduced RCS inventory condition to support RCP seal replacement work. The following items i
were observed during this evolution: Containment Closure Capability - Containment was 1 l established and maintained during the evolution. The l ] equipment hatch had been open prior to draindown, but it
- was replaced, and the personnel hatch closed, once i equipment required for the RCP maintenance was in
- containment.
1
- = RCS Temperature Indication - Normal mode 1 CETs were
) available for indication. L = RCS Level Indication - Independent RCS level indict.tions ]' were available. A Tygon tube level indicating stanopipe ! in the containment was manned during the draindown aed ! i was displayed, via closed-circuit television, in the i ' control room. The inspector walked down the tygon standpipe and verified it to be correctly aligned and free of obvious kinks which would adversely affect its 8
1' i j operation. Additionally, a wide range pressurizer level i transmitter provided level and trend indications in the control room. l RCS Level Perturbations - When RCS level was altered,
- additional operational controls were invoked. At plant l
- daily meetings, operations took actions to ensure that !
maintensnee did not consider performing work that might l effect RCS level or shut down cooling. RCS Inventory Volume Addition Capability - Three [ charging pumps and a HPSI pump were available for RCS i addition. l RCS Nozzle Dams - Due to the type of outage, the nozzle ! dams were not installed this time. Vital Electrical Bus Availability - Operations would not I release busses or alternate power sources for work ! during this evolution. Both EDGs were operable, as were all offsite power sources. l Pressurizer Vent Path - The manway atop the pressurizer has been removed to provide a vent path, j The inspector observed control room activities during the RCS draindown to reduced inventory conditions. The evolution was performed in accordance with OP 1-0410022, Rev 21, " Shutdown i Cooling," Appendix A,'" Instructions for Operation at Reduced l Inventory or Mid-Loop Conditions," and OP 1-0120021, Rev 38,
" Draining the Reactor Coolant System." The inspector verified that specified conditions were met prior to the' evolution.
)
The inspector found that operators controlled the evolution i well, that appropriate cross checking between level indications were performed, and that procedural requirements 4 for waiting periods between draining stages were met. The licensee exited reduced inventory conditions following the RCP seal replacements on August 7.
- 5) Shutdown Cooling Relief Valve Lift A. Background On February 28, while placing the 1A SDC train in service, the licensee experienced a lift of IA LPSI pump !
suction relief valve V-3483 (see IR 95-04). The valve : did not reseat, and the loss of RCS inventory was abated by closing LPSI hot leg suction isolation valves V-3480 and V-3481, which isolated the relief valve from RCS pressure. The root cause of the lift was determined to be water hammer, which resulted from passing relatively hot RCS fluid through the suction line at high velocity 9
. e 1 i
j
'as the LPSI pump was started. As corrective action, the licensee revised OP l-0410022, " Shutdown Cooling," to change the methodology of starting the LPSI pump to the following:
'
- Shut LPSI pump discharge isolation and LPSI
- header isolation valves
<
- Start the LPSI pump Immediately open the LPSI pump isolation valve l
- Throttle open two LPSI header isolations to 150 .
- gpm per header l
- Run for 15 minutes
- Start the second pump
- Throttle open the remaining LPSI header isolation -
l valves to 150 gpm per header
- Wait 5 minutes 1
- Incrementally open header isolation valves to i
! obtain full flow. 4 The licensee reasoned that th5 methodology would result in a slow increase in flow, allowing controlled system ! heatup and minimizing the potential for water hammer. ] B. LPSI Discharge Isolation Valve Lift
- On August 10, while placing the Unit 1 SDC system in i service to support a cooldown required due to inoperable
- PORVs (see IR 335/95-16), ' V-3439, the A LPSI header 3 thermal relief, lifted resulting in a loss of approximately 3500-4000 gallons of RCS, coolant in the i
Unit 1 Pipe tunnel. The following timeline was developed from operator interviews, logs and l instrumentation data: 2 0018 A LPSI pump start (ANPS, NWE, Logs) i Pressurizer level begins to drop (strip chart 1 i data) ; i 0025 ANPS directs SNP0 to tour pipe tunnel due to ' l , minor reduction in pressurizer level (ANPS) ; No increases in HUT, RWT, etc noted (ANPS) ' i SNPO reports no unusual conditions in pipe tunnel ! 0105
- B LPSI pump Pressurizer levelstart recovers (ANPS, NWE, Log)illates (strip and osc
' chart) 0140 Cooldown flow established (ANPS, NWE) i 0210 Fire watch calls control room, reports water i issuing from watertight door isolating pipe tunnel from RAB (ANPS, NWE)
- ' 0215 SDC secured (ANPS, NWE)
Pressurizer level increases and stabilizes (strip l 1 chart) l 0226 Floor drain isolation valves (FCV 25-1 through 7)
- 10 d
4 i d
___ _ __ _ _ _ _ . _ _ _ _ _ . . . . _ - _ _ . _ _ . _ . ~ . ._,_ P noted to be closed on control panel (ANPS, NWE) ! Drain valves subsequently-opened (ANPS, NWE) Flooding in RAB ONOP entered (ANPS) Water levels in pipe tunnel weren't dropping due to clogged floor drains (NWE) 0345 Water in pipe tunnel pumped . by maintenance personnel to floor drains in RAB '(ANPS) ; Operators cycle various isolation valves looking for leak > 0611 1A LPSI pump started.with NWE. observing in pipe ; tunnel (ANPS) ' 0612 NWE identifies V-3439 as passing water (ANPS) l The licensee concluded that the cause of the relief i valve lift was a pressure surge while. LPSI pumps were i operating in a low-flow condition. The combination of i RCS pressure (a maximum of 267 psia at the time) and l LPSI pump discharge head at essentially no flow ! (approximately 182 psid) combined with possible , perturbations (when starting the pump) was considered i enough to challenge the relief valve setpoint (485-515). This condition existed from the time the 1A LPSI pump ! discharge isolation valve was opened until operators initiated flow through the LPSI header isolation valves. l V-3439 was designed to provide a 10 percent blowdown, ; which, if applied to the lower acceptable lift setpoint 1 of the valve (485 psig), would require a 48.5 psia reduction in pressure to allow reseat. Given these : parameters, should V-3439 open, RCS pressure would have { to drop to 436.5 psia to allow valve resent (assuming : only a 10 percent blowdown). The volume of the RCS and ' pressurizer would preclude such a reseat until significant volumes of coolant were lost. The volume of coolant lost during the event was estimated by the inspector, based upon floor layouts as displayed on drawings. Given water depths reported by the NWE (up 'to approximately 14" in some areas), the inspector estimated that approximately 3500 gallons were lost. The CVCS makeup integrator, measuring volume added to the VCT in maintaining pressurizer level on , setpoint, indicated that 4000 gallons were added to the ! VCT. l The licensee concluded that the closed floor drain isolation valves, HCV-25-1 through 7 (a set of 7 ganged valves) were the result of valve stroke testing in preparation for Hurricane Erin. During testing conducted by control room operators, some of the valves had failed to stroke properly. As a result, the valves 11
3 were left closed for troubleshooting and were never , i reopened. OP l-0010123, Rev 99, " Administrative Control of Valves, Locks, and ' Switches," required, in step 8.1.6, that "All valve or switch position deviations or ! l ! lock openings shall be documented in Appendix C, Valve Switch Deviation Log..." 1 The inspector reviewed , archived Appendix C logs completed in July and August ' } and control room open Appendix C logs and found no '
- evidence.that HCV-25-1 through 7 were logged as being i
out of position. The failure to enter the valves' , closed status into the valve deviation log is an example '
- of a violation (VIO 335/95-15-01, . " Failure to - Follow i Procedures," Example 4). STAR 950917 was initiated to i develop a PM for verifying that floor drains were '
! Jnclogged. L i i The lii:ensee prepared an evaluation of the effects of I i the subject setpoint/ blowdown values on plant operation. ' } JPN-PSL-SENP-95-101, Rev 1, " Assessment of the Effects i on Plant Operation of Lifting the LPSI Pump Discharge Header Thermal Relief Valve," concluded that the subject j condition would not have a significant effect on safe < plant operation during normal, shutdown, and design ! basis accident conditions. In reaching this conclusion, j the evaluation noted the following: As flowrate through the relief valve (at lift
- setpoint pressure) was approximately 40 gps, the
- loss of inventory was within charging system j capacity (44 gpm per pump)'.
j. During the injection phase of an accident, the LPSI pumps would draw _. suction from the RWT, thus pressure developed by the pump would not compound 5 a high pressure suction source and the relief ; j valve's lift setpoint would not~ be challenged. ; a - The relief valve in question discharged to a
- floor drain which directed flow to the safeguards l l room sump. The sump was designed to be pumped '
j down in level to the EDT automatically when offsite power is available. Thus, with offsite power available, no flooding hazard would exist. Under conditions with no offsite power available, ! the water level in the safeguards room (after the j sump overfilled) would not rise to the level of
- the HPSI pump motors until approximately 7 hours
- after the lift. Before this time elapsed, the i
licensee reasoned that sump high level alarms would alert operators to the event, allowing i operator intervention prior to the loss of the ! HPSI pump.
/ ! 12 e
" The licensee noted that, while SDC was assumed to be placed in service during postulated small ;
a break LOCAs, ESDEs, and SGTRs (when RCS pressure !
- may have been high enough to have led to a relief i valve lift), the FSAR analysis demonstrated that l
- fuel damage (and thus the release of significant i
amounts of radioactive material to the RCS) was ,
. involved only because of extremely conservative l assumptions. The evaluation we:t on to state that "A review of FSAR analysis of small break LOCAs, ESDEs and SGTRs demonstrates that these accidents will' not result .in fuel damage if assumptions that reflect the actual operating history of the plant are applied. Therefore, the radiological consequences of these FSAR accidents I will not be increased and the FSAR offsite doses remain bounding."
The inspector .took exception to the licensee's conclusion. The subject passage was included in Section 4 of the evaluation, " Analysis of Effects of Lifting V3439," in a section entitled " Increases in Radiological Consequences of Design Basis Accidents." The inspector found 'that, in choosing to neglect design basis assumptions in their analysis of the event (specifically, a return to power and fuel failure resulting from the most reactive rod failing to insert), the licensee did not evaluate the increases in the radiological consequences of design basis accidents. Rather, the licensee evaluated the radiological consequences of a less significant set of accidents and concluded, without providing quantitative results, that the radiological consequences of design basis accidents bounded the noted relief valve lift. While the inspector agreed with the licensee's position that the circumstances assumed in design basis accidents were, 1 probablistically, of low likelihood, the. inspector pointed out that .the assumptions were the approved licensing bask of the plant and, as such, provided the appropriate common ground upon which to evaluate the , event's' significance. The inspector brought this to the attention of the licensee, who stated that they would ; consider the issue. At the close of the inspection ' period, the licensee had not presented a final position-, on the issue. As a result, this issue will be tracked / as an unresolved item (URI 95-15-.04, " Adequacy of / Engineering Evaluation Regarding Unit 1 Loss of[ Inventory via V-3439"). y On August 12, the inspector requested data on approximately 25 relief valves on both units which communicated with the RCS in some way. The requested 13
.. -. - - . .- . - - - . - .. = - . . - _ - _ - . . - . _ . . - I
. 1 4-
]
1 data included lift and blowdown setpoints, tolerances, relief capacity, and normal operating pressures 4 experienced by the valves. Shortly after requesting the e information, the licensee informed the inspector that a i team had been formed to evaluate all safety-related ; relief valve data. The team included members from '
- i. Engineering, Maintenance, Operations, Tech Staff, and l Licensing. J l The team's review was documented in JPN-SPSL-95-0334,
- ' "St. Lucie Units 1 and 2 Design Review of Safety Related 1 Relief Valves," transmitted to the site by letter dated August 30. The inspector found the methodology of the study to be sound, considering worst case combinations of system operating pressures, relief valve setpoint, and blowdown. Relief valves were evaluated for their j margin to lift and blowdown margin (the difference between resent pressure and normal system operating pressure). The document reported that, of 114 relief valves reviewed, 8 valves on Unit I and 5 valves on Unit
! 2 required further review due to unacceptable margins of f lift or blowdown. Corrective Actions were specified for j the following valves: l Unit 1 Valves i V2324, V2325, and V2326 - Charging Pump Discharge i Relief Valves - MEP 107-195M was issued to reduce the design superimposed backpressure from 165 psig to 115 psig. 1 V2345 ' - Letdown Relief Valve - PC/M 108-195 issued to reduce letdown backpressure to 430 psig and to reduce the valve's blowdown from -25 percent to 15 percent. I
- V3412 - HPSI IB Discharce Header Relief Valve -
EP 115-95 was issued to increase the design setpoint from 1735 psig to 1750 psig and to reduce blowdown from 25 percent to 10 percent.- V3417 - HPSI Pump 1A Discharge High Pressure Header Relief Valve -design setpoint increased from 2400 psig to 2485 psig and blowdown reduced from 25 percent to 15 percent. V3468 and V3483 - SDC Suction Relief Valves - STAR 950430 was issued to evaluate new setpoints and blowdown values. Unit 2 Valves 14
- -. 1 l
i.'
+
V2345 - Letdown Relief Valve - At the close of the inspection period, an EP was being prepared i to implement actions similar to those implemented
- on Unit I for this valve.
- - . V3412 - HPSI 2B Discharge High Pressure Header
- Relief Valve - At the close of the inspection
- period, an EP was being prepared to reduce blowdown from 25 percent to 10 percent.
i . V3417 - HPSI Pump 2A Discharge High Pressure Header Relief Valve At the close of the ! inspection period, an EP was being prepared to i increase the valve's setpoint from 2400 psig to j 2485 psig and to reduce blowdown from 25 percent
- to 10 percent.
V3439 and V3507 - Low Pressure A and B Discharge Relief Valves - At the close of the inspection period, an EP was being prepared to increase the valve's setpoint from 500 psig to 535 psig. As a result of the licensee's investigation, and through discussions with vendors, the licensee determined that some relief valves had been provided with unacceptably high blowdown values. This was, apparently, due to
. procedural. problems at the vendor's test facility. At ,
the close of the inspection period, the vendor (Crosby) I was considering the 10 CFR 2.1 ramifications of the l issue. The licensee documented the conditions on STAR 951024. The inspector reviewed the STAR and noted that-it had not been identified as an "N" STAR (indicating a nonconforming condition). The inspector brought this to the attention of QC, and the condition was corrected. The licensee identified the affected relief valves and segregated them appropriately. The inspector reviewed the licensee's STAR database for events similar to the subject event and found the . following:
- STAR 2-950167, initiated February 20, documented the lifting of SDC heat exchanger CCW relief valve SR-14350 when stroking CCW "N" header isolation valves closed. Once open, the relief valve had to be isolated (by closing an upstream valve in the process line) to bring about a reseat.
- STAR 0-950234, initiated March 2, documented the fact that relief valves had lifted and that blowdown values placed the reseat pressure of the 15
. _ . _ _ _ _ . - . _ _ _ _ - . - . _ _ _ _ _ _ . ~ _ - - _ . - - . _ . - - - _
l
, l i
f !* valves in the operating ranges of the systems j they protected. j
- STAR- 1-950269, initiated March 10, documented i relief valve lifts on the Unit 1 CVCS letdown I line during evolutions which should not have '
challenged the valve's setpoint.
- STAR 0-950917, initiated August 18, documented l
} - the subject SDC relief valve lift. i In addition to the STARS referen'ced above, IR 95-05-01 . discussed work performed on the Unit 2 CVCS system to prevent . letdown line' relief valve' 11fts. The IR also i- described the failure of the relief valve to ressat i (once lifted) due to a blowdown value which placed the l resent pressure below the system's normal operating ] pressure. 1 The inspector reviewed the datus of the STARS listed ? above and found them all to be open. The inspector [ ' discussed the timeliness of the resolutions to the ! subject STARS with the licensee. The licensee stated that their focus had been on the methodologies for j setting blowdown values on the valves in question, rather than on the appropriateness of the setpoints
- themselves. The licensee offered STAR 950234 as being illustrative of this point. The proposed corrective actions included
i
- Completion of SRV test benches, wh'ich would allow I the licensee to better set and test _SRVs for lift 1
- setpoint and accumulation. It was noted that the j j bench had only limited blowdown test capability. l
! . Performing an engineering design basis review of I
- all safety related SRVs to validate or correct
! setpoints and issue a design document that ! summarizes the design data. l l
- Enhancing journeyman training on SRVs.
i While the inspector found the licensee's proposed i i activities prudent, it was noted that nothing precluded. ! engineering from addressing the setpoint issue earlier
- in the process. The licensee stated that the STAR was
- addressed in stepwise fashion and that the maintenance-i related items were addressed prior to forwarding the j STAR to engineering.
j The inspector found that the licensee's corrective J actions for the subject event were comprehensive and 4 l- 16 ( 4 5
f
~ sound. However, the inspector concluded that the actions could have reasonably been expected to be i performed in a much more timely fashion. The subject phenomenon was identified as early as February,1995, and repeated itself on no less than 3 separate systems,
- and on both units, prior to the most recent event. Once i focused on the issue, an engineering product of high
- quality was developed, and corrective actions initiated,
- in approximately 2 weeks and identified valves requiring i attention in a comprehensive action. 10 CFR 50, Appendix B required that, for conditions adverse to 4 quality, prompt corrective action be taken to prevent j' recurrence. The licensee's failure to take prompt corrective action to the February / March events is a
- violation (VIO 335/95-15-02, " Failure. to Take Prompt l Corrective Actions for Repeated Relief Valve Lifts").
- . 6)- Containment Spraydown j A. Background
- The St. Lucie Unit 1 LPSI and CS systems are shown ir l Figure 1. The two systems are. interrelated in that they share the SDC heat exchangers. In an accident mode, the SDC heat exchangers serve to cool water drawn from the a containment sump prior to delivery to the containment environment via the containment spray headers. .
Referring to Figure 1, the accident mode flowpath for l CS, train A, involves water traveling -into the A CS 4 ! ! pump, through the SDC heat exchanger, and to the A CS ! header in containment. In a SDC mode, the SDC heat
- exchangers, in conjunction with the LPSI pumps, serve to '
. remove heat from reactor. coolant. The flowpath in this
- mode- (again, for the A train) involves water flowing from the RCS hot leg and through the A LPSI pump. The i fluid flow is then split at FCV-3306, with some water i passed through the valve and the balance diverted l through the SDC heat exchangers, through MV-3456 and/or j MV-3457, and returned to the LPSI system for delivery to n the RCS cold legs, i ;
- During power operations, the two systems are isolated
! from one another and each is aligned to perform its ! safety function. In the case of the CS system, this i alignment involves an open flowpath from the RWT, L through the CS pumps, and up to FCV-07-1A and FCV-07-1B, i normally closed ADVs which receive open signals in t l response to a CSAS. B. LPSI System Venting In February, the licensee experienced a waterhammer I 17 i, L i
event in the Unit 1 LPSI system while placing SDC in service (see IR 95-04). The licensee determined that one of the potential contributors to the event was air, trapped in system piping. At approximately the same, the licensee identified a Unit 2 LPSI pump in an air bound condition during a surveillance run of the pump.
; In response to these events, the licensee developed aggressive venting programs for the systems. As a part of the effort, OP l-0420060, " Venting of the Emergency
- Core Cooling and Containment Spray Systems," was developed. The procedure required, in part, that 3 venting be performed following SDC system operation.
The procedure was approved on August 13. As a part of the venting procedure, the licensee pressurized the lines leading to the SDC heat exchanger via the LPSI pumps and systematically directed flow to the RWT in an effort to sweep air from the system. The boundary of this venting process included the CS lines up to the CS header isolation valves. C. FCV-07-1A Inoperability On August II, CS flow control valve FCV-07-1A failed a stroke time test and was declared 005. As shown on
- Figure 1, the valve isolated the A CS header from the CS 4 system outside containment. The valve was designed to
, open on a CSAS and was a fail-open A0V. The valve was ! required by AP l-0010125A, Rev 39, " Surveillance Data Sheets," Data Sheet 8A, " Valve Cycle Test - Non-Check i Valves," to stroke in less than 8 seconds. In the j failed test, the stroke was recorded as 20.3 seconds. As a result of the failed' surveillance test, STAR 950869 1 was generated. The stroke time failure was documented + and the STAR was assigned to Engineering for disposition. Engineering proposed placing the valve in its safeguards position (open) and prepared SE JPN-PSL- , SENS-95-016, Rev 0, " Alternative Valve Position for { Spray Header Isolation Valve 1-FCV-07-1A." The inspector reviewed the subject SE. The purpose of , the valve and its relationship to containment isolation and containment boundary integrity were found to be appropriately considered. The SE concluded that no unreviewed safety question was introduced by placing the valve in an open position. The SE went on to provide 3
" required / recommended" actions:
4
- Administrative controls, consisting of caution 4
tags and the installation of plastic covers over switches, were required to be implemented locally , 18 8
__ _ . . _ . ~ _ _ _ _ __ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ i 1 l* and at the RTGB for CS pump 1A to prevent
- inadvertent operation of the pump.
- Operators were to be informed of the new valve alignment with emphasis given to CS pump ,
surveillances and A SDC train operation. j . Procedures were to be reviewed for impact. The f SE stated that, in lieu of. procedure changes, administrative controls may be used while the i
. valve was open.,
i j The SE was approved by the FRG on August 12. Upon completion of the evaluation, the STAR was turned over
- to Mechanical Maintenance with a required action of j restoring the valve to original design and to perform a
- root cause investigation into the failure. The inspector noted that the subject STAR included no l indication that the required actions listed above had
- been completed prior to Engineering releasing the STAR
- to Mechanical Maintenance and prior to' Operations
- repositioning FCV-07-1A. The inspector questioned the '
i STAR coordinator as to who was responsible for ensuring i that the SE's ~ required actions were complete and was
- informed that Engineering, as the organization responsible for the resolution, was responsible. The l- same question was posed to the Engineering Chief Site i Engineer, who stated that the responsibility for
] completing the action belonged to Operations. The ! inspector reviewed QI 16-PR/PSL-2, Rev 1, "St. Lucie , Action Report (STAR) Program," and found that the . . procedure was unclear as to who was responsible for ! ensuring the activities were completed. As a result the l inspector concluded that a weakness existed in the STAR
- program with regard to ensuring that required corrective i actions were documented and completed' .
. On August 15, a Night Order was issued which informed
- operators that the unit would be operated with FCV-07-1A l open. The Night Order went on to state "See attached
- Engineering evaluation which includes actions to be
[ taken to avoid an accidental spraydown of containment." ! The SE limited its consideration for the potential of } inadvertent spraydown to inadvertent CS pump starts, ! except as provided in the second required action , summarized above. On August 16, caution tags were hung ! and the valve was taken to an open position. j D. Containment Spraydown On August 18, venting of the LPSI A train was commenced per OP l-0420060, Rev 0, " Venting of the Emergency Core j 19 L . . - _
i i
. Cooling and Containment Spray Systems." When the A
- i. train was pressurized through the SDC heat exchangers, i the open flow path created to the A CS header through
- FCV-07-1A allowed water to be drawn from the RWT and j passed into the containment atmosphere via the spray
. header. l
- Operators were alerted to the event by an annunciator j indicating high' reactor cavity inleakage. Indicated
! flow into the cavity was increasing rapidly and.
- operators entered ONOP 1-0120031, Rev 23, " Excessive i Reactor Coolant System Leakage.'"- Approximately one
- minute after the annunciator was received, operators identified the flowpath leading to the. spraydown and j secured the A LPSI pump. The spraydown resulted in a
- slight decrease in containment temperature and pressure.
l The licensee noted that 90 percent of containment smoke i detectors alarmed or faulted and an electrical ground
- developed in the IA2 SIT sample valve as a result of the j event.
- l E. Impact on Unit 1 i
' The licensee determined that approximately 10,000 gallons of water from the RWT was transferred to ! containment during the event. The water was borated at
- approximately 2200 ppm. The spray resulted in an i increase in contamination -
with levels exceeding lx10'dpm/100 levels -ins cm {de containment, in many areas. i
- Following the event, the licensee placed a hold en all
- work on Unit 1. The unit was maintained stable in Mode
! 3 and management announced that it would conduct a i series of meetings with all plant personnel to discuss j the recent events on Unit I and to reiterate management-4 expectations for worker performance.. Meetings were held on August 18 in which the Division President, the Site Vice President, and the Plant General Manager. stressed the need for worker vigilance, procedural compliance, and a questioning attitude on the part of all plant personnel. Additionally, plant management made plans to cool down Unit I to allow for a decontamination of containment, a repair of FCV-07-1A, and a number of other work items prior to returning the unit to service. The licensee's initial plans for containment cleanup did ; not bring the contamination levels to pre-event conditions. After discussions with management, a decision was made to expand the scope of this cleanup and decontamination to reduce the need for additional cleanup during the next refueling outage. 20 6
i i
- The inspector toured the containment on August 19. HP 4
briefings prior to entry ir.dicated that the majority of
- the contamination was in a smearable form. Containment
- cleanup had begun, and guidelines had been developed and i
. promulgated under LOI-HP-23, " Decontamination Following l Inadvertent Spraydown of the Unit 1 RCB." The inspector noted that the 62 ft. elevation of containment had been j separated into quadrants for initial decontamination. While light water spotting was noted on the outer surfaces of some equipment, no obvious boron deposits , were identified. Water was observed to be puddled in j upturned I-beams supporting floor grating, but floor j surfaces were dry. t . l The licensee evaluated the event in Engineering Evaluation JPN-PSL-SENS-95-017, " Assessment of i Inadvertent Containment Spray Event." Items considered 4 in the evaluation included: Boric acid corrosion of carbon steel components, i potential effects on EQ and non-EQ ! instrumentation and electrical equipment. l j = Potential effects on cranes and supports
- Potential effects on snubbers 1
. I Potential effects on containment coatings.
Corrective actions resulting from the _ evaluation included a comprehensive inspection of components inside 4 containment. Included were visual inspections of all ! snubbers inside containment following containment washdown for decontamination. The inspection list ' compiled by engineering included items to be inspected by tag number, the type of inspection to be performed, , i acceptance criteria, and actions to be performed if l acceptance criteria was not met. In all, approximately { [ 1000 individual inspections were performed. Of the
- items inspected, only minor deficienci.es were i identified. i 4
i F. Evaluation of the Licensee's Activities
- The inspectors concluded that the root cause of the
- containment spraydown event was a failure of OP l-0430060, Rev 0, " Venting of the Emergency Core Cooling and Containment Spray Systems," to require a verification of initial conditions. Specifically, the ,
procedure failed to verify that the CS system was in an 1 alignment which was appropriate for the evolution being conducted. The procedure was revised to remove the i 1 21 I i
. - . - ~ - - - . . _ . - - - - - -- - - . - . - . - - . - . - - - - - 9
-subject portion, leaving only static venting, on September 1. The licensee reached a similar conclusion in LER 335/95-007, and added that contributing factors included operators failing to realize that plant conditions at the time of the evolution would result in the event. Additionally, the licensee identified that the decision to defer the repair of FCV-07-1A contributed to the event. The failure to include appropriate initial conditions in OP l-0430060 constitutes a violation (VIO 335/95-15-03," Inadequate Procedural Initial Conditions").
The inspectors reviewed the licensee's corrective actions as they related to containment inspections following the event. The . inspectors found that the licensee's evaluation of the event and the inspection scope resulting from the evaluation was in agreement with the NRC position on the subject (as described in the NRR DST Safety ' Evaluation on the subject, transmitted to regional offices via letter from T.E. Murley,on March 13, 1991). The licensee's inspection was determined to be comprehensive in scope and detail and adequate to ensure future component reliability.
- 7) Primary Water Storage Tank Overfill On August 19, at approximately 5:30 p.m., the Unit 1 RCO directed the SNPO and ANPO to fill the PWST. At approximately 7:45 p.m. , the " Primary Water Tank Level High/ Low" alarm annunciated in the control room. The RCO directed the SNPO to have the ANP0 secure the fill valve to the PWST while making his rounds. The decision to delay securing the valve was based on the RCO using a tank strapping table in the control room which showed a margin of approximately 1.5 feet from the high . level alarm to tank overflow. At 8:30 p.m., a call was received from the Unit I containment ramp that the PWST was overflowing. At that time the ANPO and SNP0 were directed to immediately secure from filling the PWST. The fill valves were then closed. It was estimated that about eleven thousand gallons overflowed form the tank. Chemistry samples found that no release limits were exceeded as a result this event.
The cause of this event appeared to be inappropriate and untimely operator response to an alarm coupled with an existing operator work around on the level control system for the PWST. The PWST level control valve LCV15-6 had a history of unreliability. Because of this unreliability, the operator had been manipulating V15106 or V15105 which are in series with LCV15-6. If this condition had been corrected, the system would have been able to automatically maintain PWST 22
. - . . . -.. -. . -- . .- . . . - .- _ .-~ . . - -
. level.
- 8) 2A Heater Drain Pump Trip At 8:20 a.m., on August 23, the "LP Heater 2-4A Level Hi/Lo" '
annunciator alarmed in Unit 2 control room. The operator 4 observed that 2A condenser back pressure had increased from !
- 4.5 to 4.9 inches Hg. Immediately thereafter, the 2A heater drain pump tripped. The control room operator immediately
) entered ONOP 2-0610031, Rev 13, Loss of Condenser Vacuum, and i i began reducing power to maintain condenser back pressure to l
- less than 4.0 in Hg. Power was reduced and the unit was l
. stabilized at 82 percent. The inspector responded to the j control room and observed this power reduction.
An investigation of the event by the licensee found that relay 63X-4A (a GE HGA relay), common to both the 4A alternate and ' 5A normal heater drain valves had failed. This failure caused the 4A alternate drain valve solenoid to de-energize and the valve to fail open. It also caused the 5A normal drain valve to fail closed. These failures resulted in a rapid decrease
- in level in the 4A heater and tripped the 4A heater drain 4
pump. l The inspector found that operators response to the event was timely and correct. The failed relay was subsequently
- replaced. An investigation by the licensee determined that
- the relay failure was due to aging. A review of other applicable uses of this type relay by the licensee found and
] replaced several other HGA relays in the heater drain system. ! The inspector noted that at least eight other heater drain pump trips had occurred over the past two years. None of j these trips were the result of a HGA relay failure. The 3 licensees' review of this and other recent HDP trips led them i to install a PC/M in the heater drain pump protection circuiting during this outage that should result in a reduction of these and similar HDP trips. The inspector found that the licensee's corrective action for this event was detailed and thorough. However, taking into consideration the previous number of HDP trips that had occurred and the licensee's knowledge of this problem and the needed changes clearly indicate that corrective action on this item was not timely. This item is identified as a weakness in corrective action.
- 9) Control Room Logs On August 24, during a review of the Unit 2 control room RCO log, the inspector noted an entry which stated that 2B EDG had erratic load swings during the performance of the monthly 23
4
- surveillance tests. Further review of the log indicated that
- the EDG was taken out of service to replace an air start i solenoid valve and then tested and returned to service. The RCO, on the shift after this item occurred, was questioned on i the entry involving the erratic load swings and was not aware i of the cause or any corrective action taken on this potential deficiency. This item was di.scussed in detail with the system engineer who was able to satisfactorily address this ites.
l
'AP 0010120, Rev 74, " Conduct of Operations," section 2.A.3, requires that problems associated with major equipment be I logged. The inspector noted that the control room log should 1 have contained adequate information to allow the operator on, ;
a succeeding shift to clearly understand this potential 1 problem and know if it had been adequately addressed to ensure operability of this ESF component. In addition to the above, on September 1, a review of the Unit , 1005 log found that containment purge valve FCV-25-4 had PW0s I 95013857 and 95004327 and STAR 94110479 issued against it. I The valve had been placed in the failed closed position but I had not been entered in the 005 log. OP 0010129, Rev 24, i
" Equipment- Out of Service," section' 3.2, required that I inoperable TS equipment that is out of service be logged. l Upon identification by the inspector this item was entered in I the 005 log. I On September 2, the inspector noted that clearance 1-95-009-011 had been issued to deenergize IB EDG fuel oil transfer pump to permit work on a local switch. A review of the 005 log and control room log also found that this had not been entered in either as required by the clearance procedure OP 0010122 step 5.6.5. A discussion.with the RCO revealed that he did not think this entry was necessary since the EDG was out of service for other maintenance activities. This item was discussed with the ANPS who directed that the appropriate l log entries be made.
The inspector noted that all of the above items were .in a safe condition and did not affect system operability. These items do indicate a weakness in logkeeping that could result in operating the plant with equipment out of service that could be required for that operational mode. This item is identified as a weakness in logkeeping and a failure to follow procedures, and is an example of a violation (VIO 335/95 i 01, . " Failure to follow Procedures," Example 5).
- 10) Operation of IB LPSI Pump with the Suction Valve Closed On August 29, Unit I was in mode 5 with both trains of SDC in operation. At 2:20 p.m., the B train of SDC was placed in standby to allow a SDC hot leg suction valve leak test to be 24 I
e I w m
I . i l' performed as specified in data sheet 25 of AP l-0010125A.
- Step 6.5.4.B of this test left one hot leg suction valve V3651
, open and the other hot leg injection valve closed at ' the
- completion of the test. The SDC normal operating procedure OP
- 1-0410022, section 8.3, was then used to return the B train of i
SDC to service. Instead of using the procedure, the RCO ! ~ transposed the procedural steps of section 8.3 to a separate ! piece of paper and used this to perform the procedural steps.
- Using this guidance he failed to open and lock open B hot leg
- suction valve V3652 as required by procedure step 8.3.7.
$ T'eh IB LPSI pump was then s'arted t by the board RCO who noted i the starting surge on the pump ammeter and that the amperes had subsequently declined and steadied out at about 15 amperes. The ANPS opened the LPSI discharge. valve at the CRAC panel to re-establish flow in the B LPSI loop. The board RCO did not recognize that LPSI pump B amperes were lower than anticipated. The board RCO then went to the CRAC panel to l initiate flow to B SDC HX. ;
. i At about 4:45 p.m., the NPS identified that LPSI pump amperes l were lower than anticipated. At the same time the desk RC0 l found that the hot leg suction valve V3652 was shut. The IB LPSI was secured and the IB SDC train was returned to the standby lineup. A subsequent inspection of the pump l determined that no apparent damage had occurred during the j short period of pump operation. After an inspection and evaluation the pump was returned to service and all parameters I were normal. An ASME Section XI test was subsequently performed satisfactorily.
The failure of the operator to follow OP l-0410022 is an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 6). This failure could have resulted in the failure of the IB LPSI pump and subsequent loss of one - loop of SDC.
- 11) IB Emergency Diesel Generator Failure On August 31, the IB EDG tripped due to high crankcase pressure in the 12 cylinder engine during the performance of the monthly surveillance test, OP l-2200050B, "lB EDG Periodic Test and General Operating Instructions." Licensee personnel found that the engine coolant expansion tank had drsined and the engine oil sump level had increased approximately eight inches above normal.
Inspection by licensee personnel revealed tw .ne number nine power pack crown and cylinder head had sustained severe damage, apparently due to separation of the northeast exhaust valve head from its stem. The failed valve head became loose within the combustion chamber and during numerous strokes 25
i i4 punctured the piston crown and cylinder. The engine coolant then leaked through the cylinder head and piston into the oil , i and entered the engine sump. The source of the high crankcase '
- pressure. trip was a combination of intake air and exhaust j' gases-escaping through the failed piston into the crankcase.
j The licensee developed a root cause investigation team i composed of personnel from mechanical maintenance, technical 3 staff, site and corporate engineering, and an engine vendor
- representative. This team performed a detailed investigation.
over several days which concluded that the most probable root ; i cause was: 1
- . Cylinder number 9 lash adjuster lock nut loosened. The i lash adjuster screw was then 'able .to back out of
[ position due to normal operational vibration. l'
- As the lash adjuster screw loosened, the hydraulic i
lifters initially compensated for the increased height
- of the valve bridge assembly. ~ Eventually the increased i height of the valve bridge resulted in impact loading at i the locking ring in the lower spr.ing seat. The locking
! ring is normally unloaded during operation. . L = The impact loading eventually caused the bridge guide to i fail. This allowed further bridge movement and loss of "zero lash" in the valve train. The increased clearances resulted in impact loads being transmitted to
- the valves themselves. The bridge guide failure also )
j increased wear on the guide's lower spring seat. !
- The impact loading caused the lock grooves of both east I
! valve spring stems to deform due to fretting wear from l ! the valve spring seat locks. The northeast valve spring , t seat eventually failed due to hoop stresses induced by j the wedging action of the seat locks. ! . The failed spring seat was retained by the helical i . spring coil which initially prevented valve stem i detachment. The additional clearances provided by the t failed spring seat allowed the seat locks to ! progressively fail due to wedging and point loads until 1 - they finally released the valve and allowed it to drop into the engine cylinder. The valve head separated from the stem due to impact loading by the piston. The separated valve head was then loose in the cylinder and punctured the piston crown and the cylinder head when the piston rose.
. Engine tripped on high crankcase pressure due to flow of turbocharged inlet air and exhaust gases through the 26
~. ,
j i '
- piston into crankcase. Water from broken cylinder head water passages flowed through the piston into the t
crankcase to drain the expansion tank. Smaller + particles from the piston and cylinder head were blown into the exhaust ducting. )s = The inspector conducted daily meetings with the manager of the root cause' team and discussed the status of their
- investigation and findings. He also observed numerous facets 1
of the licensee investigation, inspections, and repairs to the j affected diesel engine. j' The initial p'lans called for replacement of the number 9 power o ! pack (cylinder and piston) and' inspection of all shaft i bearings. After inspections found several metal parts from l the damaged number 9 cylinder in the exhaust ports of other i cylinders and on the engine exhaust turbocharger intake screens, the engine. inspection was expanded to include all i cylinders, exhaust headers, and bearings. This inspection i found some rust in number 12 cylinder and led to replacing l that power pack also. The inspection of the remaining , j cylinders also led to replacing number 3 and 4 cylinder heads due to leaking valves. I' ' After the above repairs and bearing inspections, the engine was reassembled and flushed with new lubricating oil and all filters were replaced. As a result - of the root cause j investigation the lash adjuster locking nuts were torqued to a 50 ft-lbf value given by the EDG service company (this value l had not_ been previously specified in the vendor manual or i licensee maintenance procedures). This torquing was i accomplished on all cylinders for both the 1A and IB Unit 1 ) diesel engines. After a ceries of maintenance runs and adjustments on September 5 and 6, the IB EDG successfully I completed its surveillance test and was declared operable on September 6. l The inspector found the root causes investigation team to be i composed of well-qualified individuals. They pursued the issues associated with the failure in a diligent manner and i i worked well with the personnel performing engine repairs. The inspector noted that the licensee's service vendor plans to l also perform a root cause investigation of this failure. l The inspector was very impressed with the teams that worked ! the engine ~ repairs around the clock. Their detailed ! investigation resulted in expanding the scope of inspection
- and repair to cover the entire engine. The overall repair '
, effort was strongly supported ' by site and corporate i engineering and resulted in timely completion of the repairs. j
- 12) Unit 2 Main Generator Hydrogen Overpressurization 1 27 i
t
l 4
, On September 7, at approximately 1:30 a.m., a NPO noted that i the hydrogen pressure on Unit 2 generator was at 58 psig..
1 This pressure is normally maintained at 57 to 60 psig.- The i
~
l NPO contacted the RCO and notified him that he would be ! bringing the pressure up to approximately 60 psig. When the -
- hydrogen supply header was aligned to the generator, control room annunciator "H2 Manf Sply Press Hi/Lo" alarmed as
- expected due to low header pressure and remained illuminated.
1 The NPO left the area to continue his rounds. At ! approximately 2:00 a.m., the control room requested the NPO l come to the control room and assist in a digital electro
- hydraulic loss of load test. This test was corapleted at about
- 2
- 24 a.m. The NPO then completed his round and returned to
- his office area.
t At about 3:20 a.m., the.ANPS noticed that the "H2 Manf Sply Press Hi/Lo" annunciator was illuminated. The RCO checked the 1 hydrogen pressure and found it to-be 80 psig. The RCO then i directed the NPO to secure the hydrogen and reduce the j generator gas pressure to 60 psig. ! Licensee investigation of this event determined that the NPO and control room operators' did not apply sufficient detail to the progress of this evolution. The NPO allowed himself to be ; assigned to another task and lost control of the status of the 4 evolution. The generator hydrogen filling evolution was not 3 l l adequately tracked by the RCO and ANPS. They also permitted ! i the "H2 Manf Sply Press Hi/Lo" annunciator to stay illuminated !
- .for about two hours when the filling evolution should have 1 taken approximately 30 minutes. The licensee also found that !
4 a generator high gas pressure alarm should have sounded and !- actuated an annunciator in the control room. The local alarms j were found to be inoperable with existing PW0s that required j work.
- This event clearly pointed out a failure of the NPO and RCO to
! maintain status while adding hydrogen to the main generator
' and the failure to reset a control room alarm. It also showed that an operator must stay aware of the status of alarms on j equipment and take compensatory actions if normal annunciators j are not available. This item is identified as a weakness.
A subsequent inspection and evaluation by the equipment vendor ! determined that the generator had not been damaged as a result l of this event. I c. Plant Housekeeping (71707)
- Storage of material and components, and cleanliness conditions of 4
various areas throughout the facility were observed and no safety and/or fire hazards were identified. j 28
l, . , t ! a t [' d. Clearances (71707) i i During this inspection period, the inspectors reviewed the following j tagouts (clearancep):
- l-95-009-011 -
on EDG 18 fuel oil transfer pump. The 4 j inspector found the clearance tag in place and the breaker in !
- the off position as required. l I} =
2-95-09-002 - control valve V-3661 for SIT outlet drain valve
- to RDT. The inspector found the valve in the closed position 1 with fuses removed from RTGB-206.
l
- No deficiencies were identified.
- l
- j. e. Technical Specification Compliance (71707) i
! Licensee compliance with selected TS LCOs was verified. This ! included the review of selected surveillance test results. These i verifications were accomplished by direct observation of monitoring '
- instrumentation, valve positions, and switch positions, and by
- review of completed logs and records. Instrumentation and recorder t traces were observed for abnormalities. The licensee's compliance t with LC0 action statements was reviewed on selected occurrences as i they happened. The inspectors verified that related. plant
! procedures in use were adequate, complete, and included the most l recent revisions. ' ! f. Effectiveness of Licensee Controls in ' Identifying, Resolving, and j Preventing Problems (40500) ! 1) Licensee Self Assessment I i 4 The inspector reviewed a special QC assessment of decisions j that led to the inadvertent spraydown of Unit I containment.
- This assessment was requested by the FPL Nuclear Division Vice i President and. focused on the plant's decision to operate Unit l 1 with FCV 07-1A in the open position and the development and execution of new procedure OP l-0420060, " Venting of Emergency i
Core Cooling and Containment Spray System." This review found , that operating the CS system in an abnormal lineup and ; executing a new procedure under this condition, coupled with ! i operator error resulted in spraydown of Unit I containment. ! The assessment also noted that schedule pressure may have l prevented timely repair of the CS valve FCV 07-1A. The
- inspector noted that the assessment was detailed and provided j some recommendations for improvement.
i ! The inspector also noted that the assessment identified that i the quarterly surveillance test directed that FCV 07-1A be
, lubricated immediately prior to the performance of its j scheduled surveillance. The inspector questioned this j .
29 i i
practice since prelubricating the valve prior to performance of the surveillance test would not result in testing the valve's ability to provide the required response time during an actuation. The licensee agreed with this and changed the procedure ~to delete the prelubrication under TCN 2-95-177 on September 7, 1995. The inspector also questioned why QA had not documented this deficiency under the STAR program as required by QI 16-PR/PSL-2, Rev 1, "St. Lucie Action Report (STAR) Program," Section 5.1, " Initiation of a STAR Form." As a result of the question, a STAR was generated on September 6. The failure to document the subject finding via the STAR process is an example of a violation (VIO 335/95-15-01, " Failure to Follow Procedures," Example 7).
- g. Unit 1 Restart Activities The inspector accompanied maintenance QC on a walkdown of the Unit
- 1. containment prior. to unit restart. This inspection by QC was conducted after departmental heads had completed their final inspection, as specified in AP 0010728. It was noted that these department - tours had been completed and signed off (with a few exceptions for items that would be as a part of unit restart). The inspector and QC identified approximately ' 40 deficiencies that .
needed to be corrected prior to unit restart. These included: Burned out lights Missing covers on electrical outlets and components Electrical box and panel covers that had not been tightened Areas that needed additional cleaning Some small trash and debris on top of components A scaffold that had not been removed j Missing screws and bolts in various components !
. Missing condulet covers !
The inspector noted that the majority of the deficiencies were the responsibility of Electrical Maintenance. A meeting was held with the Maintenance Manager to discuss the items after the inspection was complete. He indicated that these items would be corrected prior to restart and that responsible managers would be counseled on this item. The inspector found that the QC walkdown was very thorough. Discussions with QC found that QC had conducted several inspections prior to this final closeout inspection to verify that containment was being prepared for closeout. IR 94-24 noted that at the completion of the Unit I refueling outage in November 1994 the NRC also accompanied QC on the final closecut inspection and identified t
, similar conditions to that found in this inspection. That IR also identified that heavy management reliance was placed on QC to verify the readiness of containment closure. Although containment was 30
4 returned to a final satisfactory condition it appears that licensee management is employing QC in a line function rather than quality verification role.- This item is identified as a management weakness.
- 4. Maintenance and Surveillance
- a. Maintenance Observations (62703)
Station maintenance activities involving selected safety-related systems,and components were observed / reviewed to ascertain that they were conducted in accordance with requirements. The following items were considered during.this review: LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as I required. Work re' quests were reviewed to determine the status of outstanding jobs-and to ensure that priority was assigned to safety-related equipment. Portions of the following maintenance activities were observed:
- 1) PWO 61/5570 and PWO 61/5571 - Remove PORV 1402 and 1404 from pressurizer, bench test, repair as necessary and reinstall.
The valves had been identified as inoperable and the above PW0s were generated to remove the valves, determine the cause of failure and correct. The valves were removed and worked using MP 1-M-0037, Rev 6, " Power-Operated Relief Valve Maintenance." The inspector observed selected portions of the valve disassembly and troubleshooting to determine the cause of failure. These efforts involved several shifts over several days. This work was accomplished in a contaminated work area in Unit 2 RAB. The inspector noted that HP coverage was provided and that a vendor representative assisted maintenance in this effort. The inspector also noted that continuous supervisory oversight and engineering support were present in the field to provide for a timely repair of these components. These items were worked around the clock since they delayed plant restart. The inspector also noted that calibrated tools were being used and that QC provided coverage of this job. The inspector found that work procedures and PWO were in the field and being used. At the completion of the above work, the inspector reviewed the completed work package documentation and found that TC had been implemented for required procedure changes, repair parts, and work was correctly documented, and other support documentation was properly filled out. 31
^
i Overall, the personnel performing this task were adequately j qualified and used the appropriate procedures. The overall
- work effort resulted in identifying, correcting the problem l and returnin'g the PORVs to service. Adequate supervisory, engineering, and vendor support was provided to successfully
- complete the task in a timely manner. See IR 95-16 for a
.- detailed description of the root cause of the noted PORV inoperability.
- 2) PWO'1230/65 Perform PCM 11-195 on DG 1A/IB.
The inspector, while conducting routine. plant inspections, observed that work on this-modification was in progress on DG IB. Two electricians were completing the work activities associated with installing new splice boxes for the trip solenoids on the 12 and 16 cylinder engines for DG 18. - The inspector reviewed the PWO and procedure that the technicians were using. He noted that the work was nearly complete on the 12 cylinder engine, but only the first few steps of the procedure had been signed off. He questioned the electrician as to what work had been completed and the electrician stated that he had terminated the wiring, torqued the connections, and applied several layers of different types of tape in the 1 sequence indicated by the PC/M. Noting that only a few steps of the PC/M had been signed off, the inspector asked specific questions as to the wiring identification, torquing requirements, and sequence and type of tapes used. l The electrician was unable to locate the guidance provided for. wiring identification for correct termination and admitted that, although he had torqued the connection 'to the correct q value, he did not document this in the work package when the ; step was accomplished. He also stated that he had taken over l this job from another individual and had only scanned through i the work package instructions and details. Further review of ! his work activity and the work package by the inspector ! determined that the connections had'been correctly made and the correct torque value had been used. The circuitry was tested on the night of August 31 and ; performed satisfactorily. The inspector discussed this item ; in detail with the Maintenance. Manager and noted that not l filling out procedural steps as they are accomplished, doing i only a cursory review of a work package, and not being j knowledgeable of all aspects of the job can lead to serious errors or mistakes in the performance of maintenance activities. The Maintenance Manager stated that he agreed with the inspector's observations and that corrective action would be taken in.this concern. ADM-08.02, Rev 7, " Conduct of Maintenance," Appendix 5, Step 5, required that procedures be present during work and that 32
l l
- .
- 5 3
s i individual steps be initia10d once performed. The noted i failure of the electrician to initial procedural steps on an I ! as-completed basis is an example of a violation (VIO 335/95- ' 15-01, " Failure to Follow Procedures," Example 8). j- 3) PWO 95-02-4066 Remove Cylinder Head No. 9, Inspect for Damage. ' d This PWO was later expanded to perform repairs. The inspector ! conducted periodic inspections of these activities as they { occurred over a period of approximately one week. Additional details and evaluation of this work is contained in paragraph j 3.b.11). e i
*E l
':- l l
33
# .. b l (5ggapoq()/
gl19pc % vLW cL/r><rLien l
' y)Q o
.h 0% ;
SqId e N TSC LgEDENFORCEMENTPANEL i dAP Nkgo Ep' *0NNAIRE sf A f. /. M-M Dw &+ l"* ^*/#* INFORMATION RE0VIRED TO BE AVAILABLE FOR ENFORCEMENT PANEL f PREPARED BY: DATE PREPARED: May 16.1995 l NOTE: The Section Chief is responsible for preparation of this questionnaire and its distribution to attendees prior to an Enforcement Panel. (This information I will be used by EICS to prepare the enforcement letter and Notice, as well as the ! transmittal memo to the Office' of Enforcement explaining and justifying the Region's proposed escalated enforcement action.) ,
- 1. Facility: St. Lucie .f i
Unit (s): 1 Docket Nos: 50-335 i License Nos: DPR-67 ' Inspection Dates: NA 1.- Lead Inspector: NA
- 2. NOTES:
A. A draft Notice of Violation, including the recommended severity i level for each violation, should be enclosed. The violation (s) in I the Notice should be Carefully considered by both the inspector and-Section chief, and should be complete regarding the specif_ic [
. requirement to be cited and the appropriate level of specificity as to how and when the requirement 'as violated.
B. Copies of applicable Technical + Ncations or license conditions cited in the Notice should be enclosed.
- 3. Identify tha reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2) ' .;.
I.C.3 or I.D.4
- 4. What.is the apparent root cause of the violation or problem?
coanitive operator action - failure to inform the facility licensee U the he had manipulated the wrono valve while performina a procedure 6
)
--This document contains predecisional information-- i
'It can not be. disclosed outside NRC without the i aproval .of the Regional Adninistrator l O >
I
U-t
- 5. State the message that should be given to the licensee (and industry) through this enforcement action.
honesty is the best policy .
- 6. Factual information related to the following civil penalty escalation or mitigation factor (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation? Was it self-disclosing? Was it identified .as a result of a generic notification?)
this was identified by the facility licensee's investiaation of the events surroundina a temporary loss of decay heat removal L i
- b. CORRECTIVE ACTION: Although we expe;.t to learn more information regarding corrective action at the enforcement conference, describe t preliminary information obtained during the inspection and exit I interview. !
t the operator involved voluntarily terminated his employment with FP&L and his NRC operator's license was terminated What were the uimediate corrective actions taken upon discovery of the violation, the development and implementation of long-term --
, i l corrective action and the timeliness of corrective actions? -
l NA ' l \ l l
--This document contains predecisional information--
It can not be disclosed outside NRC without the approval of the Regional Adninistrator ; a l
. _ _ __ ._ _ _ - - __ _ _ _ - - _ _ _ _ _ ._.. . _ _. _ ._ _ _._m
, I -
i-l l' What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis? ; i
'the facility licensee was very aaaressive in determinina the root l cause of the event. The root cause analysis appears thorouah.
- c. LICENSEE PERFORMANCE: This factor takes into account the last two years.or the period within the last two inspections, whichever is '
l longer. ~ List-past violations that may be related to the current violation ' i- (include specific requirement cited and the date issued): >. NA i . ; i ! Identify the applicable SALP category, the rating for this category i and the overall rating for the last two SALP periods, as well. as any j trend indicated: ; N _A i ! d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities for the j licensee to discover the violation sooner such as through normal surveillances, audits, QA activities, specific NRC or industry ! notification, or reports by employees? y i there were no orior opportunities to identify this 4 l 1 a d
--This document contains predecisional infort..ation--
It can not be disclosed outside NRC without the , 4 approval of the Regional Adninistrator o 4
t
)
s
.l. ) j
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation i identified during this inspection? If there were, identify the l number of examples and briefly describe each one. -
i NA I I
- f. DURATION: How long did the violation exist? i
- g. ADDITIONAL COMMENTS / NOTES:
i
--This document contains predecisional information--
It can not be disclosed outside NRC without the approval of the Regional Adninistrator I
NOTICE OF VIOLATION Utility Florida Power and Light Docket Nos. 50-335
- Unit (s) 1 License Nos.DPR-67 ,
During an NRC inspection conducted on violation (s) of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Action,10 CFR Part 2, Appendix C, the violation (s) is listed below: 10 CFR 50.5, Deliberate misconduct requires that any employee of a licensee may /. - l 4 not: deliberately submit to a licensee information that the person submittin t (U " l information knows to be incomplete or inaccurate in some respegerial_t he j NRC. I l Contrary to the above, on March 4,1995, a licensed operator, docket number xxxxxx, operated a valve that caused a temporary loss of shutdown cooling at St. Lucie Unit 1, repositioned the valve to restore shutdown cooling, and failed to inform licensee management that his operation of the valve was the cause of the loss of shutdown cooling. l l This is a Severity Level _III Violation (Supplement I). Pursuant to the provisions of 10 CFR 2.201, Duke Power Company is hereby required to submit a written statement or explanation to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555, with a copy to the Regional Administrator, Region II, and a copy to the NRC Resident. Inspector at the facility within 30 days of the date of the letter transmitting this Notice of Violation (Notice). This reply should be clearly marked as a " Reply to the Notice of Violation" and should include for each violation: (1) the reason for the violation, or, if contested, the basis for disputing the violation, (2) the corrective steps that have been taken and the results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the date when full compliance will be achieved. If an adequate reply is not received within the time specified in this Notice, an order or Demand for Information may be issued as to why the license should not be modified, suspended, or revoked or why such other action as may be proper should not be taken. Where good cause is shown, consideration will be given to extend the response time. Dated at Atlanta, Georgia this day of January 1993
!4 !
! ESCALATED ENFORCEMENT l q- PANEL QUESTIONNAIRE i INFORMATION RE0VIRED TO BE AVAILABLE FOR ENFORCEMENT PRE-PANEL i
. PREPARED BY: Mark S. Miller _
4 i NOTE: .The Section' Chief tis responsible for_ preparation of this questionnaire l' and its distribution to attendees prior to an Enforcement Panel. (This !" .information will be used by EICS to prepare the enforcement letter and Notice, ! as well'as the transmittal memo to the Office of Enforcement explaining and l justifying the Region's proposed escalated enforcement action.)
]
! 1. Facility: St. Lucie { L Unit (s): 1 : l 7 Docket Nos: 50-335 l
.)
- License Nos: DPR-67 1 j Inspection Dates: March 5 - April 1. 1995 Lead Inspector: R. L. Prevatte l i 2. Check appropriate boxes:
l [X]- A Notice of Violation (without "boilerplate") which includes the , j recommended severity level for the violation is enclosed. l l I 4 [] This Notice has been reviewed by the Branch Chief or Division l Director and each violation includes the appropriate level of : l specificity as to how and when the requirement was~ violated. [] Copies of. applicable Technical Specifications or license i . conditions cited in the Notice are enclosed.
- 3. _ Identify the reference to the Enforcement Policy Supplement (s) that best !
fits the violation (s) (e.g., Supplement I.C.2) l I.C.3 I.D.3 4
.. .,.. _ ., _ ,.. .RE.E.,,, _ ,. _ , _ .
,T CAN NOT BE APPROVAL DISCLOSED OF THE WITHOUT THE
,OUTSIDE NRC,STRATOR REG 0NAL ADMIN -
4 j
O ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE
=4. What is the apparent root cause of the violation or problem?
The "croblem" was a loss of shutdown coolina. The aooarent root cause - was a misDositionina of V3651 (1B SDC hot lea suction isolation valve) i by a licensed operator
- 5. . State the message that should be'given to the licensee (and industry) through this enforcement action.
Either: 11 Timely and effective compliance with off-normal operatina ) procedures must be affected, or hl Intearity of licensed operators is of paramount importance in
)
assessina event root causes i 2
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matri.9 and 10 CFR Part 2, Appendix C, Section VI.B.2.): )
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation? l Was it self-disclosing? Was it identified as a result of a generic notification?)
The event was self-disclosina. The most probable root cause was determined by the licensee.
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit interview.
The licensed operator deemed to be responsible for the event was relieved of licensed activities and suspended with Day pendina comDietion of the licensee's investication. What were the immediate corrective actions taken upon discovery of ; the violation, the development and implementation of long-term corrective action and the timeliness of corrective actions? l The " violation" in this case is not the loss of shutdown coolina ; itself and as such the licensee has not taken actions with reaard i to the violation. As reaards the probable root cause for the ! condition, the licensee performed in-depth reviews to ascertain that the root cause was not related to eauipment malfunction. The operator-in auestion was relieved of duty within 24 hours of the event.
~ THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION--
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 2
ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE ! What was the degree of licensee initiative to address the 1 < violation and the adequacy of root cause analysis?- e r $' The licensee was aaaressive and timely in investiaatina the event. :
~
i A number of reviews were conducted by independent teams and . individuals to helo determine the most-likely root cause. While , the evidence suaaests stronalv that operator error was the root ' [
-cause, the licensee has fully eXDlored the technical possibilities
- j. in an-attempt to ensure that an unidentified eauipment failure is t i
i not left in the unit. !~'
- c. LICENSEE PERFORMANCE: .This factor takes into account the last two years or the period within the last two inspections, whichever is ;
longer. 4 < List past violations' that may be related to the current violation . (include specific requir'ement cited and the date issued): - ! None i Identify the applicable SALP category, the rating for this
- category and the overall rating for the. last two SALP periods, as l
- well as any trend indicated
i ). Oc rations - Cateaory 1 i
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportuuities for the [
licensee to discover the violation sooner such as throppi normal
- surveillances, audits, QA activities, specific NRC or industry :
; notification, or reports by employees? :
1 -
- 5. No i . .
i- e. MULTIPLE'0CCURRENCES: Were there multiple examples of the violation identified during this inspection? If there were,.
- identify the number of examples and briefly describe-each one.
4 No. The violation aDDears to be the result of the actions of a sinale individual . 1 . g f. DURATION: How long did the violation exist? The violation occurred in an isolated fashion. 1 l
--THIS DOCUMENT CONTAINS PREDEc!SIONAL INFORMATION ~ j IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 3 l
lF. . ; i-ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE [ ADDITIONAL COMMENTS / NOTES: , l On March 4, Unit 1- experienced a loss of shutdown cooling while realigning
- shutdown cooling trains. The event lasted approximately 14 minutes. Initial -
!: lRCS conditions were 99'F and 247 psia. The RCS was in a solid water j condition, with pressure being maintained through CVCS letdown pressure control. . Peak RCS temperature during the event was'113*F and peak pressure ! was 343 psia. 4 At 9:35 p.m., an RCO was placing the A SDC train in standby after placing the { B SDC train in service. OP 1-0410022, revision 19, " Shutdown Cooling," e section 8.2 described the method for placing one SDC train in standby with the other. train in service. The methodology (presented in the order specified by i the procedure) involved securing the pump in the train of interest, verifying , adequate SDC flow remained, shutting the affected pump's discharge valve, and j then shutting the affected pump's suction valve.
- .The performance of these steps required operation at two different control
! panels; the Control Room Auxiliary Console (CRAC) which contained controls for , , LPSI punp discharge isolation valves, and RTGB 106 which contained controls ; i for LPSI pumps and LPSI pump suction isolation valves. The two panels were
- located at extreme ends of the Unit I control room, requiring operators to
- - traverse the control room in the course of placing a train in standby. The
i SDC realignment was being conducted by the Desk RC0, one of two reactor . operators on watch at the time. The other reactor operator, the Board RCO, was dedicated to monitoring RCS pressure and controlling letdown flow, as the unit was in a solid water condition. A timeline was established, by the licensee, for the event based upon interviews with the operating crew, output from the Sequence of Events Recorder (SOER), and Emergency Response Data Acquisition Display' System I (ERDADS). Major aspects of the timeline are as follows: - 21:41:20 Desk RC0 secures 1A LPSI pump 21:42:20 Annunciator - V3651 (IB LPSI pump SDC suction isolation valve) closing with IB LPSI pump running Desk RCO goes to CRAC to shut A SDC discharge valve 21:43:20 No SDC flow registered on SDC flow instrument (<1500 gpm) Desk RCO returns to RTGB 106
- Board RC0 notes pressure increasing
- Board RCO goes to RTGB 106 and notes annunciator
- Board RC0 goes to CRAC to verify valve positions
- Board RCO returns to RTGB 106, then to RTGB 104
- Desk RC0 notifies crew of mid-position indication of V3651 21:43:42 Annunciator - V3651 permissive not met - pressure >270 psia
- Board RCO notes pressure at 320 psia and increases letdown 21:44:35 Annunciator - LTOP anticipatory - pressure >330 psia
--THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION" IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 4
- . - - - _ _ - - . _ - . -=. . - - . - . . - - - - - - . - - . -
ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE 21:44:44 Desk RC0 secures 1B LPSI pump b
- Desk RC0 notes again, and crew acknowledges, dual indication of V3651 .
21:44:50- RCS peak pressure reached - 343 psia 21:45:00 Board RC0 secures 1B charging pump 21:45:41 V3651 open permissive satisfied 21:58:40 SDC > 3000 gpm restored time not precisely established, but sequential based upon interviews The licensee concluded that the loss of SDC was the direct result of V3651 closing. ERDADS data, indicating reductions in SDC flow, combined with SOER data would support the conclusion. In considering the cause for the valve closure, the licensee pursued parallel paths which considered electrical malfunction and operator error. With regard to possible electrical malfunction, the licensee composed two independent cross-functional teams to consider failure scenarios which might lead to the closure of V3651. The teams analyzed the control circuitry for the valve and postulated electrical faults that might result in valve closure. Field tests for insulation between conductors and conductors and ground were conducted with satisfactory results. Additionally, inspections were made of valve limit switch components and physical conditions at the valve. No deficiencies were noted. The two teams concluded that there was no credible electrical fault that could lead to the noted valve closure. The licensee then conducted two additional reviews of the circuitry by engineering personnel not previously associated with the event. Similar conclusions were reached. . The inspector reviewed the applicable control wiring diagram for V3651 and determined that the licensee's conclusions were sound. The inspector further concluded that any electrical fault which may have lead to valve closure must have existed for a period of approximately 60 seconds (the valve's stroke time) and then cleared, allowing the valve to open. The licensee convened a meeting of the crew on watch during the event, provided a facilitator and ERDADS/SOER data and tasked the crew with creating possible scenarios which could lead to the noted behavior. - The crew determined that the only credible cause for the event would involve a mispositioning of the key-lock control switch for V3651, followed by a return uf the valve's control switch to the open position after the valve had cycled closed. Given the timeline for the event and the results of crew interviews, the only person in a position to make such an error was the Desk RCO. The assumed mispositioning would involve the Desk RC0 securing the 1A LPSI pump and attempting to close V3481 (the 1A LPSI pump SDC suction isolation valve) prior to moving to the CRAC to close the 1A discharge isolation valve.
--THl$ DOCUMENT CONTAINS PREDECISIONAL INFORMATION *
!T CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMIN!$TRATOR 5
ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE Instead of closing V3481, the Desk RC0 would have to mistakenly operate the control switch for V3651. This would appear credible, as the two switches are oriented beside one another. This scenario would allow V3651 to stroke closed while the Desk RC0 moved to the CRAC and would result in the first annunciator . noted. This scenario would also represent a departure from the governing ! procedure, as the suction valve is listed as the last valve to be operated in placing a SDC train in standby. j The scenario in question would further require the Desk RC0 to realize his i error upon returning to RTGB 106 and return the control switch for V3651 to the open position in an attempt to correct the error. Given that RCS pressure exceeded the pressure interlock associated with V3651, the valve would fail. to l cycle completely open until pressure was reduced below the interlock setpoint. l This would explain the dual position noted by both the Desk RC0 and the crew. l The Desk RC0 was presented with the licensee's conclusions and has maintained that he did not misposition V3651. The licensee relieved the Desk RC0 of , licensed duties and placed him on suspension with pay while investigations 1 were being conducted. As data began to indicate that electrical malfunction i was not credible, the licensee withdrew the Desk RCO's site access. ! SAFETY CONSE0VENCES l I The safety consequences of this event were minor. TS were not violated. TS ' 3.4.1.4.1 requires, in Mode 5 with RCS loops filled, at least one shutdown cooling loop be operable and either one additional shutdown cooling loop be I operable or secondary side water level of two steam generators be greater that l 10% of narrow range indication. During this event, both shutdown cooling l loops were operable, RCS loops were filled, and both steam generators had ; water level greater than 10% of narrow range indication. TS 3.4.1.4.1 al so l requires that at least one shutdown cooling loop be in operation. With no l shutdown cooling loop in operation, Action Statement b. allows one hour to ! initiate corrective action to return the required shutdown cooling loop to ! operation. In this event, one shutdown cooling loop was restored to operation in about 14 minutes. l TS 3.4.13 requires, in Mode 5, that two power operated relief valves (PORVs) be operable, with their setpoints selected to the low temperature mode of operation and a setpoint of less than or equal to 350 psia during isothermal conditions when the temperature of any RCS cold leg is less than or equal to , 193 degrees F. During this event, two PORVs were operable with their ' setpoints selected to the low temperature mode of operation and a setpoint of 346 psia. The PORVs each have a capacity of 321 gpm, and are designed to prevent RCS P/T limits from being exceeded during design basis overpressurization events due to mass or energy addition to the RCS. In addi. tion, the two shutdown cooling relief valves each have a capacity to relieve the flow from three 44 gpm each charging pumps.
--THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION "
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 6
. .- . _~ - - . - - - - . - - - - . - - - - . . - . - - _ - .-
p. l l' 4 ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE l DRAFT VIOLATIONS b A '. Technical Specification (TS) 6.8.1.a required that written procedures be
- established, implemented, and maintained covering the activities .;
! recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February , l -1978. Appendix A,' paragraph 1.d, includes administrative procedures _for l procedure adherence. Appendix A, paragraph 5, includes Abnormal ! Operating Procedures.
- Procedure QI 5-PR/PSL-1, Revision 60, " Preparation, Revision, Review / Approval of Procedures," Section 5.13.2 stated that all
! procedures shall be. strictly adhered to. Off-Normal Operating procedure
.1-0030131, Revision 59, Plant Annunciator Summary," requires, in part, that upon receiving annunciator R-30, "LPSI PP IB RUNNING /V-3651/3652 -
! CLOSING," operators try to open Shutdown Cooling valves and,'if no response is-obtained, stop the IB Low Pressure Safety Injection Pump. e i Contrary to the above, on March 4, 1995, at 9:42:20 p.m., the R-30
- annunciator was received in the Unit I control room without operators j properly verifying Shutdown Cooling valve positions or securing the IB LPSI pump. As a result, Shutdown Cooling flow was lost when V3651
- achieved a closed position approximately one minute later. The IB Low l Pressure Safety Injection Pump was not stopped until approximately 2 minutes and 22 seconds after the annunciator was received.
The loss of Shutdown Cooling resulted in a temperature. excursion from 99
.F to 114 F and a pressure excursion from 247 psia to 343 psia.
This is a Severity Level IV Violation (Supplement 1). B. Technical Specification (TS) 6.8.1.a required that written procedures be established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A, paragraph 1.d, includes administrative procedures for procedure adherence.' Appendix A of Regulatory Guide 1.33, Revision 2, paragraph 3.c, includes operating procedures for. the Shutdown Cooling system. Procedure QI 5-PR/PSL-1, Revision 60, " Preparation, Revision, Review / Approval of Procedures," Section 5.13.2 stated that all procedures shall be strictly adhered to. Procedure OP 1-041022, Revision 19, " Shutdown Cooling," paragraph 8.2 required that the Shutdown Cooling Train A be returned to a standby condition by, sequentially,; stopping the 1A low Press.ure Safety Injection Pump, ensuring adequate Shutdown Cooling flow, closing V3206, and closing V3481.
- THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMIN!$TRATOR 7
ESCALATED ENFORCEMENT PANEL OVESTIONNAIRE Contrary to the'above, on March 4, 1995, Shutdown Cooling Train A was improperly placed in a standby condition when V3651 vis operated in lieu of V3481. Additionally, the valve was manipulated out of sequence with the noted procedure in that it was operated prior to closing V3206. As a result, shutdown cooling flow was lost for about 14 minutes while the ' unit was in Mode 5. This is a Severity Level IV Violation (Supplement 1).
~
1 Comments on DRAFT VIOLATIONS Above ) With regard to VIO A, this would give us an opportunity to take enforcement action without explicitly determining root cause. It would also send a message that .the crew, not an individual, is responsible for safety. The l potential' downside of this approach is that the " Purposes and Discussion" i portion of the CN0P includes words like...
"This procedure provides an informative guide to operations l personnel...The actions listed are intended to be a guide...and are not
. intended to be a substitute for good judgement..."
i As a result, the licensee could make the case that the actions stated in the ONOP constitute " guidance" and so are not explicitly binding on the operators. Our response would then be that, by responding to_the first annunciator PROMPTLY, the event may have been avoided. We could cite a failure to follow OP 1-0410022'(VIO B above), in that V3651 was shut - mistakenly, in~ lieu of V3481 - out of the order specified in the procedure; however, this may not really speak to the root cause or significance of the event. In'either case, to cite at all based upon operator error would be to decide that operator error was the root cause without knowing conclusively. If we are to conclude that operator error was the root cause, it would seem to me that the larger issue is operator integrity, as the operator in question continues to proclaim innocence. As such, it might be better to send a message which speaks to integrity by acting on the individual's license. A letter of reprimand or something similar might be the way to go.
--THIS DOCUMENT CONTAINS PREDECISIONAL INFORMATION -
IT CAN NOT BE DISCLOSED OUTSIDE NRC WITHOUT THE APPROVAL OF THE REGIONAL ADMINISTRATOR 8
l e l l l 9 i ESCALATION AND MITIGATION FACTORS (57 FR 5791, February 18, 1992) , IDENTIFICATION C0RRECTIVE LICENSEE MtIOR IEALTIPLE DURATION ACTION PERFORMANCE (PPORTlallTT TO OCCURRENCES l I IDENTIFY 4
+/ 50% +/ 50% +/ 100% + 100% + 100% + 100%
, Licensee Timeliness of Current Licensee should Multiple used for identified (M) corrective violation is an have identified examples of significant (To be applied action (M) isolated violation violation regulatory even if LDid NRC have failure that is sooner as a identified message to licensee could to intervene to inconsistent result of prior during licensee. (E) have accomplish with licensee's opportunities inspection identified the satisfactory good exh as audits (only for SL 1, violation short term or performance (M) (E) 11 or 111 sooner) remedial action vlotations) (E) (E)) NRC identified Pronptly Violation is opportunities ~ OtHER CONSIDERATIONS-(E) developed reflective of evaltable to schedule for licensee's poor discover 1. Legal aspects and potential.. Long term or declining violation such litigation risks corrective performance (E) as through action (M) prior 2, Negligence, careless dis-notification regard, willfulness and (E) management invoLvesent self- Degree of Prior Ease of earlier 3. Economic, personal or disclosing licensee performance and discovery (E) corporate gain (M-25% if initiative (M) effectiveness there was [To develop of previous 4. Any other regulatory framei-initiative to corrective correct've work factors that need to be identify root actions and actice w considered: pending action cause) root cause) similar with regard to licensing, violations comission meeting, or press conference. Licensee Adequacy of the SALP - Period of time identified as root cause consider: between 5. What is the intended message a result of analysis for SALP 1 - (M) violation and for the licensee and the. generic the violation SALP 2 - (0) notification industry? notification (M) SALP 3 - (E) received by (M) Licensee (E) ----- --- NOTES. - --- - Cowprehensive Prior Similarity corrective enforcement between the action to history violation and prevent including notification occurrence of escalated and (E) similar non escalated violation (M) enforcement Imediate Level of corrective management action not review the taken to notification restore safety received (E) and compliance (E) SAFETY $!GNIFICANCE: In determining the safety significance of a violation in conjunction with the enforcement process, the evaluation should consider the technical safety significance of the violation as well as the regulatory significance. Consideration should be given to the matter as a whole in light of the circumstances surrounding the violation. There may be cases in which the technical safety significance of the matter is low white the process control failure (s) may be significant, and, therefore, the severity level determination should be based more on the process control failure (s) than on the technical safety issue. The following factors should also be considered: 1) Did the violation actually or potentially impact public health and safety? 2) What was the root cause of the violation?
- 3) Is the vlotation an isolated incident or is it indicative of a programmatic breakdown? 4) Was management aware of or involved in the vlotation? 5) Did the violation involve willfulness?
. e BRIEFING ON USE OF DISCRETION TO PROPOSE CIVIL PENALTY
/ FOR IN0PERABLE PORVs AT ST. LUCIE The design and operation of the PORVs are discussed in Attachment 1. Both PORVs were inoperable from the time they were installed in the RCS on November 5,1994, during the 1994 refueling outage until they were removed and reworked in August, 1995. MISSED OPPORTUNITIES
- 1. Maintenance on the PORVs did not include precautions to ensure operability and protect aaainst a common mode failure.
The PORVs were last reworked in November, 1994 in the Unit I refueling outage. The rework was conducted by Furmanite. Disassembly and inspection revealed that the main disc guide wrs installed upside down, with the holes (required to vent the space below the main disc) located at the upper extreme of the main disc cavity such that proper venting below the main valve disc could not take place. Maintenance was performed by the same two workers. The maintenance procedure which directed the installation of the main disc guide, did not include a QC hold point to verify proper installation. No independent verification method was used to ensure the valve was properly assembled. The main disc guide was the only component which could be installed l improperly and result in undetected inoperability. The licensee could have used several standard methods to ensure that a common mode error did not cause both PORVs to be inoperable, i.e., use of different work crews on each i vd ve, independent verification of the maintenance work steps, or an appropriate QC holdpoint.
- 2. Post Maintenance Testina was limited to a seat leakaae test and the stone / responsibility for testina was not understood between Operations and ,
Maintenance l Post-maintenance testing was limited to a bubble test for seat leakage prior to reinstallation. Procedures specifically excluded lift test requirements with an explanation that the valve was lifted based upon solenoid valve input. The procedure did not require a verification that the valve would change state under pressure prior to installation. Operations accepted the PORVs from Maintenance with the assumption that they had been properly tested and, as such, considered them operable upon installation. Maintenance personnel thought in-situ surveillance testing was to be used as the post-maintenance test. Maintenance and Operations were under completely different impressions of the status of the PORVs following installation in the system. As a result of this misunderstanding, the PORVs were placed in the RCS and declared operable without reasonable assurance that the PORVs would perform satisfactorily in the LTOP conditions which would exist prior to performance of the routine surveillance test.
- 3. Inservice surveillance testina did not demonstrate that. after complete valve disassembly and reassembly, that the valve would chanae state under pressure.
The ASME stroke testing method is discribed in Attachment 2. A discussion h of the ASME Code testing requirements is provided in Attachment 3. 3 VN Surveillance tests performed on November 25, 1994 and February 27, 1995, a used acoustic data, as opposed to system pressure reduction derived from Y
l valve capacity, to indicate valve position. The licensee failed to c recognize in its review of the acceptability of this test method that the PORV pilot valves allowed sufficient bypass flow to actuate the acoustic monitors. An indication of only one lit acoustic monitor LED was sufficient to pass the test. Only the acoustic indication was used when other control room indications could have been used to confirm valve operation. Test acceptance limits derived from the valves' design documentation were not , used. Specifically, the use of acoustic data, as opposed to system pressure ' reduction derived from valve capacity, to indicatt valve position was i_ insufficient to discern the difference between bypass flow through the PORV , pilot valves and actual changes in main valve position. On August 4,1995, the licensee perfomed an ASME Code inservice test and 1 did not receive an acoustic signal in the control room, but an increase in tailpipe temperature was observed, and an increase in acoustic levels was i recorded on a plant computer. RCS and Quench Tank parameters in the control i room exhibited less than expected changes. The licensee assumed the acoustic monitor was inoperable. The licensee then contacted the vendor to , discuss possible reasons for the observed valve performance. While evaluations were being conducted, the unit was taken through LTOP conditions , to Mode 4. At 7:03 p.m. on August 9, 1995, the valves were retested and 4 found to be inoperable based, in part, on observations of RCS and Quench i Tank parameters.
- 4. The indications of valve ooerability after a unit trio were missed.
On_ July 11, 1995, Unit 1. experienced a high pressure trip (see IR 95-14).
- According to the licensee, at the time of the trip, both PORVs lifted. The 4
conclusion was supported at the time by the inherent design of the system, the fact that acoustic data indicated that the PORVs lifted, and noted increases in Quench Tank temperature. Upon a re-review of data (which suggested that pressure drifted above the PORV setpoint, as opposed to plateauing) and an analysis which showed that the post-trip loss of heat l source acts, in conjunction with steam reliefs, to limit pressure increases, l the licensee concluded that the PORVs probably did not lift following the j trip. CONCLUSION
' Section VII.A of the Enforcement Policy allows the exercise of discretion to propose a civil penalty when the case involves poor licensee performance. The licensee's performance in this case was particularly poor throughout the control of the maintenance and testing of these valves and led to a common mode failure of ,
the PORVs. Expected provisions to ensure valve operability were not implemented. ' A critical point in the reassembly did not have a QC holdpoint; other independent verification methods were not employed. Engineering analysis and plant safety committee reviews of the acceptability of post maintenance testing and inservice testing contained basic flaws in ensuring methods were employed to assure operability. These flaws included accepting post-maintenance testing that only verified seat leakage prior to putting the valves back in service; miscommunication between Operations and Maintenance on scope of post-maintenance testing; and failure to provide an adequate inservice test to ensure PORV operability. Operator attention to diverse control board indications during testing was lacking and only when the one parameter that was required, i.e., the acoustic monitoring indication, failed, did operators question the other indications they were getting. The post trip data analysis during the July 1995 unit trip was not indepth. Therefore, we propose that a base civil penalty be imposed in this case to ensure the appropriate regulatory message that programs must provide defense in depth to preclude common mode failures.
~
Attachment 1
- DESIGN AND OPERATION OF THE PORVs b St. Lucie Unit I employed two PORVs. Purposes: (1) Pressure relief coincident
! ' with a high pressure reactor trip - open at 2400 psia. Accident analyses did not
! credit the valves' actuation; (2) Pressure relief under LTOP conditions - open at i two selectable LTOP setpoints based upon RCS temperature; (3) Once through cooling
- credited in the licensee's E0Ps for providing core cooling in the event of a loss of heat sink.
l , The Unit 1 PORVs were Dresser Industries Model 31533VX-30 pilot operated relief valves. The main valve (responsible for actual RCS pressure relief) was opened by the force of water or steam acting on the main valve disc / seat interface. The i main disc moved within a guide cylinder and its movement was governed both by the differential ~ pressure established across the disc and spring force which tended to-
- move the disc into a closed position.
j A ' differential pressure was established across the main disc when the valve's l pilot valve was opened, venting a space inside the main disc to a low pressure j area (the tailpipe). The pilot valve was actuated by a solenoid acting on the
- pilot valve lever, t
- When actuation was required, a signal was sent' to the actuating solenoid, which
!. stroked the pilot: valve lever to open the pilot valve. A vent path was thus-i established from the inside of the. main disc, through the pilot vr.lve, to a low l pressure area. The resulting differential pressure across the valve main disc
- opened the PORV main valve.
i t Indications of valve operation included acoustic flow monitors at the discharge of j each PORV, tailpipe temperature indication, and indication of solenoid energization. PORV operation could also be inferred from changes in quench tank
- parameters (temperature, pressure, and level) or changes in RCS pressure. Output
- of the acoustic monitors was indicated in the control room, behind the main control panels. -The discretized output was indicated by ten LEDs per instrument
- channel. On the energization of a single LED, a. control room annunciator was
! energized, alerting operators. i l 2 i
- v. , . , , . . , , _ ...r, ,_ ., - . , _ _ , . _ _ .
__. ~ _ _ . . _ , _ . _ _ . _ _ ___ __ _ ._. _... .. _ _ . _ _ _ . . _ . _ - 4 Attachment 2 j '/ ASME STROKE TESTING METHOD ASME Section XI stroke testing involved: -
- 1) placing the PORV control switches in " override" (which ensured that the valves would not open),
- 2) removing High Pressurizer Pressure bistables from the RPS cabinets (which would i have sent an "open" signal to the PORVs which would be blocked by the status of the control switches), and
- 3) for each PORV, placing the control switch in " normal," which would have sent the open signal to the PORV.
The stroke time for each PORV was measured from the time the control switch was taken to " normal" to the time that acoustic monitors indicated that the subject valve had opened. Once a valve stroke time had been obtained, the subject valve's
- control switch was returned to override to close the valve.
l' 1 4 3 4 I ) 1 ! l l ! l E i
-. . .- - - - - . . - - .--..-.---~ . - - . - . . - . - . . _ - .
s Attachment 2 Reauirement for ASME Code Testina The PORVs are classified by the licensee as safety-related and are ASME Code i Class 1, RCS pressure boundary valves. The requirement for ASME Code testing is tied down by Technical Specification 4.0.5 which requires, in part, that inservice inspection of Code Class 1 valves shall be performed in accordance with Section XI
- of the ASME Boiler and Pressure Vessel Code and applicable Addenda as required by j 10 CFR 50, Section 50.55a(g).
) The edition and addenda of the ASME Code to which St. Lucie is. committed is tied down through Florida Power and Light's Second Ten-year Inservice Inspection ! Interval Inservice Testing Program For Pumps and Valves, Document Number JNS-PSI 203, Revision.5, states, in part, that, between February 11, 1988 and February 10, 1998, the St. Lucie Unit 1 ASME Inservice Inspection (IST) Program will meet.the requirements of the ASME Boiler and Pressure Vessel Code (the Code), Section XI, 1983 Edition.
- Section XI of the 1983 ASME Boiler And Pressure Vessel Code, article IWV-3000, Test Requirements, Section IWV-3200, Valve Replacement, Repair, and Maintenance, 4
requires, in part, that when a valve or its control system has been replaced or repaired or has undergone maintenance that could affect its performance, and prior i j .to the time it is returned to service, it shall be tested to demonstrate that the 4 performance parameters, which could be affected by the replacement, repair, or
- maintenance are within acceptable limits.
4 i l t 4 i a 4
. _ - - _ . - _ . _ _ . . _ . _. - . - . __ __. . ~ _ _ - .
l i
.conocconococcococconococonococooooooooooooconococcooooooooooooooooooooooooooocco '* User name: KDL d
Queue: HPIIID-AT1-3033
- File name: DISCRE Server: AT2
- 1 Directory: *
- Descriptio . *
- November 08, 9
- 05:28pm ococo*********** ************** *********************************************
o *
- K K DDDD L
- i
- K K D DL * {
- KK D DL
- I
- E D DL *
- KK D DL *
- K K D DL *
- K
- K DDDD LLLLL l e
- l occoc***************************************************************************
*
- l
- W W ooo rrrr dddd PPPP eeeee rrrr fffff eeeee ccc ttttt *
- W Wo or rd dP Pe r rf e c c t
- i
- W Wo or rd dP Pe r rf e c t * !
- WWWo o rrrr d d PPPP eeee rrrr ffff eeee c t
- WWWo 1
- orr d dP e rr f e c t
- l
- WW WW o or r d dP e r r f e c c t
- l
- W W ooo r r dddd P eeeee r rf eeeee ccc t * '
*
- l cocce*************************************************************************** .
F s v b
i O i l l ENFORCEMENT ACTION WORKSHEET INADEQUATE DESIGN CONTROL l PREPARED BY: John W. York DATE: October 28. 1996 NOTE: The Section Chief of the responsible Division is responsible for preparation of this EAW and its distribution to attendees prior to an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and telephone bridge number to attendees via e-l mail [ENF.GRP. CFE. OEHAll. JXL. JRG SHu. LFD; appropriate RII DRP. DRS: appropriate NRR. NMSS]. l A Notice of Violation (without "boilerplate") which includes the recommended severity level for ! the violation is required. Copies of applicable Technical Specifications or license conditions ! cited in the Notice or other reference material needed to evaluate the proposed enforcement i action are required to be enclosed. l 4 This Notice has been reviewed by the Branch Chief or Division Director and ! each violation includes the appropriate level of s cifici as to how and I when the requirement was violated. i
/~ / i
@ naturr j Facility: St. Lucie i i
Unit (s): 1 and 2 i Docket Nos: 50 335, 389 I License Nos: DPR 67. NPF 16 Inspection Report No: 96 17 Inspection Dates: 10/7-11. and 10/15 18, 1996 Lead Inspector: John York
- 1. Brief Summary of Inspection Findings: [Always include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then either summarize the inspection findings in this section or reference and attach sections of the inspection report. Inspectors are encouraged to utilize the Noncompliance Information Checklist provided in Enclosure 4 to ensure that the information gathered to support the violation is complete.]
The licensee replaced some safety related nuclear instrumentation drawers during the. Unit 1 Outage. The drawers were wired backwards-because of incorrect drawings. Part of the root cause identified the lack of a proper independent verification as a potential cause. This is a violation of 10 CFR 50 Appendix B Criterion III In examining the safety aspects of this event, one additional example of inadequate
. design verification was identified for BEACON on line core performance monitoring system.
In addition to the wiring problem for the drawers, the maintenance group connected the field cables for an NI backwards because the markings on the connectors were different than on the previous detectors. An NOV was written for failure to write a Condition Report (discrepancy report) and resolve this prob 1cm prior to installation of the detector. g See attached IR feeder and proposed NOV for details. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE h9
.D ENFORCEMENT ACTION > WORKSHEET
- 2. Analysis of Root Cause:
< Lack of control and procedural adherence in the licensee's program for . i preparing and implementing Plant Change / Modifications (PC/Ms).
- 3. Basis for Severity Level (Safety Significance): (Include example from the supplements, aggregation, repetitiveness, willfulness, etc.)
Aggregation of examples and application of Supplement I. C.7. a , 4 breakdown in the control of licensed activities involving two violations that are related that collectively represent a potentially significant lack of attention toward licensed activities. The safety significance of reversing the detector inputs to the NIS drawers substantially reduced the safety margin between the TM/LP trip setpoint and the analysis limit even considering the increased TM/LP margin to the trip setpoint due to actual core operating conditions. . 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections? [by EA# supplement, and Identification date.)
'EA 96-249 - Inadequate 50.59 did not identify US0, 7/12/96 EA 96-040 - Boron Overdilution Event. Supplement 1. 1/22/96 EA 95-180 - Inoperable PORVs due to Inadequate PMT, Supplement 1. 8/4/95
- 5. Identification Credit? No The miswired NId ' rawers were identified through an event (the failure to have the system respond properly).1. e. the analysis of the data by ,
Reactor Engineering discovered the miswiring of the NI drawers but the 1 error in the drawing should have been discovered in the design control ' process. The design error associated with BEACON was identified through routine
, comparisons of actual plant data with predicted data. This error could have been discovered in the design control process.
Enter date Licensee was aware of issues requiring corrective action: 7/30/96 2
- 6. Corrective Action Credit? Yes Brief summary of corrective actions: 1 In response to the issue, the licensee adopted corrective actions which I included: ;
i e For immediate action the licensee prepared a change request for the modification package and channels A.C. and D were reconnected and testing was performed to verify proper NI response.
- A root cause/self assessment and training meeting for the Engineering Department emphasizing importance of proper design PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
. . -=~ - -.. .- .- ~ .-
I e ENFORCEMENT ACTION. WORKSEEET-verification and importance of questioning attitude. Tape was produced of this meeting for future engineering training. e Procedures (Engineering Quality Instructions) were revised to (1)- require all critical aspects be verified during the PC/M. (2) emphasize that the same level of verification is required for. 1 PC/Ms duplicated for the second unit. and (3) reinforce the !
- verification requirements for safety related drawings. j e Walkdowns will be conducted (linear NIs) to revise any design documentation and tagging. !
e ' ASI targets will be established for future trending of ASI during power ascension. e Require cross-disciplinary reviews of design inputs e Better documentation of assumptions in core design inputs and ! codes J Explain application of corrective action credit: Corrective action appears to be of appropriate scope. l l
- 7. Candidate For Discretion? N0 <
l Explain basis for discretion consideration: Since actual power conditions dia not exceed trip setpoints, no . escalation is warranted. Several examples of licensee's declining performance in engineering does not warrant mitigation.
- 8. Is A Predecisional Enforcement Conference Necessary? Yes Why: I To determine adequacy of licensee's proposed long-term corrective actions regarding backward looks at modifications ptrformed prior to the Unit 1 outage. This included discussions of other modifications that may not have been independently verified.
If yes. should OE or 0GC attend? [ Enter Yes or No]: Should conference be closed? [ Enter Yes or No]:
- 9. Non Routine Issues / Additional Information:
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT TH'i APPROVAL OF THE DIRECTOR, OE l
ENFORCEMENT ACTION
- WORKSHEET
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: (EICS to provide] [If inconsistent. include:1 Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Message:
Positive control must be established and maintained over the design process. with particular emphasis on properly performing independent design verification.
- 12. Recommended Enforcement Action:
SL III
- 13. This Case Meets the Criteria for a Delegated Case. [EICS - Enter Yes or No]
- 14. Should This Action Be Sent to OE For Full Review? [EICS - Enter Yes or No]
If yes why:
- 15. Regional _ Counsel Review [EICS to obtain]
No Legal Objection Dated:
- 16. Exempt from Timeliness: [EICS)
Basis for Exemption: Enforcement Ccordinator: DATE: t ^ PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
ENFORCEMENT ACTION WORKSHEET ISSUES TO CONSIDER FOR DISCRETION a Problems categorized at Severity Level I or II. O Case involves overexposure or release of radiological material in excess of NRC requirements. a Case involves particularly poor licensee performance. O Case (may) involve willfulness. Information should be included to address whether or not t' a region has had discussions with OI regarding the case, whether or io the matter has been formally referred to 01, and whether or not 01 .itends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included. a Current violation is directly repetitive of an earlier violation. o Excessive duration of a problem resulted in a substantial increase in risk. o Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. O Cases involves the loss of a source. (Note whether the licensee self-identified and reported the loss to the NRC.) o Licensee's sustained performance has been particularly good. a Discretion should be exercised by escalating or mitigating to ensure that the proposed civil senalty reflects the NRC's concern regarding the violation at issue and tlat it conveys the appropriate message to the licensee. Explain. PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
1 Enclosure 3 1 REFERENCE DOCUMENT CHECKLIST i l ['] NRC Inspection Report or other documentation of the case: , NRC Inspection Report Nos.: [] Licensee reports: [ -] Applicable Tech Specs along with bases: l [] Applicable license conditions 1 1 [] Applicable licensee procedures or extracts 1 [] Copy of discrepant licensee documentation referred to in citations such l as NRC. inspection record, or-test results ' [] Extracts of pertinent FSAR or Updated FSAR sections for citations i involving 10 CFR 50.59 or systems operability 1 [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [] Other miscellaneous documents (List): i i l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l 1
1 I I 1 NI INSPECTION ST. LUCIE-October 7-18. 1996 On July 30. 1996. St. Lucie Unit 1 was operating at approximately 100 % ! power when reactor engineering was analyzing the data taken during power l ascension and noted an anomaly in the results. The data indicated three of the four excore linear detectors measured core power moving to the top of the core during power ascension. This was an unexpected i ahenomena and did not agree with the trend of the power moving to the l Jottom of the core indicated by RPS Channel B Linear Range Detector. ! Control Channel #9 Linear Range Detector, and the BEACON Core Power i
- Distribution Monitoring System. Evaluation of the data collected i indicated that RPS Channels A.C.and D could have reversed (rolled) leads l of the top and bottom chambers input to the RPS drawers. ,
The modification performed during the outage associated with this problem was No. PC/M 009-195. During the outage. the licensee replaced the power range NI drawers for the Reactor Protection System (RPS) with
- new Gamma Metrics drawers. This modification combined the linear power i
- range input to the RPS and the logarithmic wide range channel into a 1 single drawer, i.e. reduced the number of drawers on Unit 1 from eight to four. This modification increased the limits of the instruments range and replaced aging equipment.
- Engineering Verification-Root Cause A design error was responsible for the reverse connection (rolled leads) on four NI safety related drawers on Unit 1. The Controlled Wiring Diagram (CWD). no. JPN-009-195-001/002 depicted the upper Uncompensated l Ion Chamber (UIC) connected to the lower UIC input at the NI drawer.
The root cause noted that the designer and the lead engineer interpreted conflicting information on the existing CWDs and made an assumption. 4 The independent verification may have caught this error had the process been properly performed. The drawings were prepared by the lead designer with input from the lead engineer. The drawings were then checked by a second designer who had no special knowledge of the NI design. This check was essentially a drafting check. The drawings were then reviewed by the lead designer and then by the engineering supervisor. Engineering Quality Instructions (01) 1.7. Design Input / Verification, dated July 5,1995, states in part that " Design verification is the process whereby a competent individual, who has remained independent of the design process reviews the design inputs. ... and design output to verify design adequacy. This independent review is provided to minimize the likelihood of design errors in items that are important to nuclear safety." Contrary to this requirement the first reviewer could not be considered as competent because he was not an engineer as required by PROPOSED ENFORCEMENT AOTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i
. -. --.. -~ . -- -- - . .-- . - - .
4 2 i 01 1.7 and the lead engineer as the third reviewer could not be considered to have remained independent of this design project. One of the action items to prevent recurrence was to check all the I&C
- electrical PC/M to see if all the drawing approval signatures could qualify as independent verifiers. The licensee found three out of eight
, open modifications where this was a potential problem, two of these modifications were electrical and one was I&C. This therefore is not an ; t isolated case. This failure to perform independent verification 1 according.to procedure is identified as exam)1e one of violation 50-335/96-17-XX Failure to Control the Design 3rocess According to the i Requirements of 10 CFR 50, Appendix B, Criterion III. BEACON Core Power Distribution Monitoring System l The licensee had installed BEACON during this refueling outage to replace the older IMPAX code used for in-core flux monitoring. BEACON provided several significant improvements over IMPAX one being real-time flux profile monitoring. This improvement permitted reactor engineering to identify the NIS problem qJickly and initiate prompt corrective e actions. During power operations, reactor engineering used BEACON to obtain the l actual in-core flux profile. The actual in-core flux profile was then ' used to verify compliance with Technical Specifications and provide calibration information for the excore NIS drawers. As part of these o routine surveillances, reactor engineering com3 ares actual in-core flux l profile to the in-core flux profile predicted ]y the core design code.
- Reactor engineering noted larger than normal errors between actual and predicted in-core flux profile. Because BEACON used the same neutronics i engine as used in the core design code, reactor engineering could not i
- explain the error and notified the corporate core design engineers. As
~ part of the process to resolve these errors, it was discovered that a j simplifying assumption, used to overcome limitations of the IMPAX, was l not accounted for in the original design of BEACON. This simplifying assumption was used because the licensee had changed the fuel design to incorporate a longer end cap to prevent debris induced fuel failures. 1 This longer end cap raised the overall core height by 2.64" causing an offset between detector midplane and actual core midplane. The IMPAX code assumed detector midplane was along core midplane and could not accommodate the 2.64" offset. Therefore, the licensee, after discussion with the fuel vendor (Siemans), used this simplifying assumption to essentially lower the core midplane by 2.64" so that final design output would be referenced to detector midplane: not core midplane. However, the engineer preparing the design input for BEACON was not aware of this simplifying assumption consequently BEACON was referenced to core midplane resulting in an increased error between the core design predicted in-core flux profile and actual in-core flux profile. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
O 3 The licensee's root cause evaluation identified lack of cross-discipline review as the significant contributor to this design error. The inspector concurred with the licensee's evaluation. Engineering Quality Instructions (0I) 1.7. Design Input / Verification dated July 5.1995, states in part that " Design verification is the process whereby a competent individual, who has remained independent of the design process, reviews the design inputs. . and design output to verify design adequacy. This independent review is provided to minimize the likelihood of design errors in items that are important to nuclear safety." Contrary to this requirement, the design inputs were not adequately reviewed by a competent individual in that the core midplane offset was not identified as a design input for BEACON. This failure to perform an adequate independent design review for the BEACON system is identified as example two of violation 50-335/96-17-XX. Failure to Control the Design Process According to the Requirements of 10 CFR 50 Appendix B. Criterion III. The safety significance of reversing the detector inputs to the NIS drawers substantially reduced the safety margin between the TM/LP trip setpoint and the analysis limit even considering the increased TM/LP margin to the trip set)oint due to actual core operating conditions. The safety impact of t1e failure to identify the core and detector midplane offset on TM/LP or LPD safety limits was minimal. CONNECTOR SWAPS AT DETECTOR 6-CHANNEL B All four of the RPS Linear Range Detectors had the connectors reversed as previously discussed but the B channel unlike the other three channels was giving the correct data. At the same time that the drawers were being replaced on Unit 1. the detector for channel B (detector no.
- 6) was being replaced as a maintenance activity. During connection of the field cables, the connections were reversed for the upper and lower detection chambers, thereby causing the B channel to record properly.
The root cause for the swap of the cables was that the new detector had different labeling than the existing cables. The existing cables were labeled TOP SIG and B0T SIG. and the new detector had A and B. The inspectors discussed this maintenance job with the I&C supervision who had supervised the latter part of this maintenance project. Several opportunities were 3 resented to the maintenance personnel, one when the detectors were checced out in the warehouse and a second time when this condition was noted in the field. Maintenance personnel should have resolved the labeling problem by writing a Condition Report (CR) and having a formal resolution. Administrative Procedure No. 0006130. Condition Reports, rev. 4. dated March 22, 1996. Par. 8.1.1.A states in part that "Any individual who becomes aware of a problem or discrepant condition . should initiate a PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
4 CR. If doubt exists, a CR form should be initiatsd". This failure to
. comply with the requirements of the administrativt. procedure is identified as violation 50-335/96-17-YY, Failure to Initiate a Condition Report for Labeling on Safety Related Dettetors.
I l PROPOSED ENForw.F. MENT ACTION - NOT FOR PUBLIC DISCL OSURE WITHOUT 1HE APPROVAL OF THE DIRECTOR, OE l
9 Q t Violation 1 with two examples. 10 CFR 50 Aapendix B. " Quality Assurance Criteria for Nuclear Power Plants and ruel Reprocessing Plants." Criterion III requires, in aart, that ... design control measures shall provide for verifying or clecking the adequacy of design, such as the 3erformance of design reviews...The verifying or checking process shall 3e 3erformed by individuals or groups other than those who performed t1e original design. but who may be from the same organization. FPL Topical Quality Assurance Report. TOR 3.0. revision 11. " Design Control." Section 3.2.4. " Design c erification." stated. in part. " Design control measures shall be established to independently verify design input... Design verification shall be performed by technically qualified individuals or groups other than those who performed the design. Engineering Quality Instructions 1.7 " Design Input / Verification." rev.1. dated July 5,1995, states in part. " Design verification is the process whereby a competent individual, who has remained independent of the design process, reviews the design inputs. ... and design output to verify design adequacy. Contrary to the above: L Contrary to the above, on July 30, 1996, it was discovered that a design change (PC/M 009-195) was completed without an independent design verification by a competent individual. Design change PC/M 009-195 to install new Gamma Metrics Nuclear Instrumentation drawers was completed by a lead designer and a lead engineer. This design change was independently verified by a second designer ; who had no special knowledge of the design. A engineering
~
supervisor approved the design. Neither the second designer or engineering supervisor had remained independent of the design l process. <
- 2. Contrary to the above, on July 30. 1996, it was discovered that an independent design review was not conducted for the installation of a new core flux monitoring computer code BEACON. During initial operation of BEACON it was found that the code did not compensate for a core mid-plane ' offset created by a previous core '
modification. The engineer who prepared the design was not aware of the core mid-plane offset and the independent review of the new BEACON code did not identify this omission. Violation 2 Technical Specification 6.8. Hocedures and Programs, paragraph 6.8.1 requires in part that written procedures recommended in Appendix A of Regulatory Guide 1.33 revision 2. February 1978 shall be established. ; implemented... PROPOSED ENFOW. EMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
4 2 Administrative Procedure No. 0006130. Condition Reports, revision 4, dated March 22, 1996. Paragraph 8.1.1.A states in part that "Any individual who becomes aware of a problem or discreaant condition ... should initiate a CR. If doubt exists, a CR form siould be initiated". Contrary to the above, on July 30. 1996, Instrument and Control technicians installing a plant design change (PC/M 009-15) did not initiate a condition report when they became aware of a discrepant condition cancerning incorrectly marked cables. They continued to install the modification and an error was made that resulted in cross-wiring of the nuclear instrumentation system. i l l
'l l
i l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
. . i f,
- . s
!' savaarrya cm m 4 4 -/s7f l
- 3 % ,. CONDITION j f a. o i. .i .,. "" O '"# "U 1 c O so =i = *=,.
- REPORT. -.. ,
. g/q /qt,
~ '
! o. o., -- . waior e y
' **' ss. J s .1.5 ? 16
/ 1. SYSTEMsMAME 6 NmWM Ide# ' ' LMIT / OCBS'CDENTD b8' 8 d' D'M i 33ug /-M M .=bdach uiccxm0E2x2eav) # # 8 / 4 *#*'a/ # ~
l mnnvnernmerna 7/.mE/W. / /4#/l EVENTDCEMME '/W# [/ I d s' *
/r 7*W'P j cuanxxxam h// M'Wl M '
carpretas l 2. w'"= ^***** **" A* """aan . ! w commomm===== 34A rLuae' Mm .;, Y-y , swes . 4svid,g,gurm4 rme r .(se) .44
~
NaeieAa waneno awt- R red * & f W se aV&AToffw n.h earive sut?. (AntJ' rennet , Asr vs. Eseast As.x). %s- l ar$rts&r- eEnir lastweraspf, Are vio~s 4.r's ame j u rn en cruxurt s 6,e 1 (sei,ijikiYoness) "3Vh c) c4um ' i l llN 4ewd, h rn son,6to4E eJo s sordeocce sab ove JoscerfEWildt .E9Mr/ #' *Eh, , i Mi=3i. 51.Y.~'; a_- 4 m neman acnmensa .. L!b ,5"M! r de n fy i sf u rrorit wwoeen , .sw, ee .1 ~r. 4 ^ Ars 'eenxHe t t M*A-j se < a / se r e.u s ag y tM._
- ____ ___________---_--- -r -
1 p,.-- - -_- m --,,,essama. : ,.~ ; .7;.g. b /, & ve tro b ral cownh$$9f'.'nEr&ofenueHWKLt'.gN f - $fsA A61d a a 2. 2k rex ~ rxe o.s.n,< rns. 'ef ,' i: . s
-w 2.:Nt*!'
1 .. * ~ 4 3 $'.'_"$E[ C1tZ. *L*!Gan ML*' _-
. - - --- ps -
l. g. I t
} 3. caxmumanaquestscrrYcrczamacxzenrusmGtr sta O No
! arsmsonucnmcmat / - Em
- /
s *
- / ,,omsnm eermeancee ouwa m m s'YB O to orsumun Amusnawrnameomaarn icosaxer O Yu Edo a ,mur -- === == - = __
a c. = o === co.c===r ===== nn l y a a.m a ,
,_ Fld/ JUTE 7%M !
, . I > >
geny /M~ [ DAIEf!BE
- m .
< /
> 5. 03 NEE"DONRDOECTM1D v
// M WAM MVESDGiCE&CrRRECT ,
z )E'.700 BDGtr [ROCFr CADE A> E ( v N 1 DCE 1 3D hk FiMTGENDLAI MANACERMBCRAF , . - - , I A i1
**Cas ARE QA RECORDS MEN N -
DeLNtE AhRESPOMBEM MC ATDatENTS ,.m, ARE. r- 3.o = w<mste f
c mm ;. . ,,
>ea n a r sw in . ---=
seer sowisy , - -i: p
- la ~rm.s ,m -=u= Fv. uno - - .
l -==== - , - - , 2 [' fee rases a wao
- 7. Tot. dpatAenns: Assaw ce,r evAu.mm is Psot@Eb W lhes 87peu,26MM _
M _. Per cMse ****8**% 8* *
- _ _per es-Pu.-serr-%-osc,, oFcuaun n I*vec Wgev.o Omscaei)
- Np-9e gener HAs 8sso.AeeMR.sD AW6 6MGN To 806 0 l
i canscomes PRxaswxr. MW-
- c. ) : LM&,mua*r.?!%G H nwemat=< "
,.4 w 7 .; 7..
u .__ ___ gl;of a j. ja .g O u a . . -u ___ __ - I
.a - . _ _
,1== '
c us .fkr .o l - ---- g,gygagagem
.g -I'"yp.
Em l g, *.- an O m samstm rwo _
===== 0 m S=
i vP ..
, ==== O ns Eife l ~* ,
l a ~ man C as GiYm cRsl naq -84C- 444A . ._ ..'. .
%%eJP5p ead "M
. + p. -ue
, a,an #N_g g , . o- s(.-- o == a= a==wa-ac m e ,im.,s ma nom.ne.no
=:a= === *-
=h* W .
- t==sussangsammes l
l st __===----- 9,.MttSM % "*_ ?4, W-Y N. N.D & '** . 1 a== *
- S E
- c'l- /
a ,. s = - [ar _[ad% - n = ar / -. N
-=
N I
- n. an-er=a==ammaman e- 7/3ervorruunam E_h. 5 W.4 sg%n ;A s- ,y a n vA GLHy yat m y&p casa 4 Pc,/,n **1-nr una Q-Ada.
I g a -- e t e= . yn e = m~-Q l I . L ., %.1 1+ kog+e'u! a 4=a%w,s p.a y l g ,g,, p... out
- r. y a, .n>s .
i 5 g4lf.n., s b *
- r A im.ae-m.s
- n. ,.nr
^
nu-w mw-1n-mu-m u Mw-n s.uy e g,:,.w
- n a --
m g *g,.06 250 W Ltv-rz~
/ $kOu a.e a ,.
Ye>1bb sr;.
. ,s,w a;
n ga ~~ - / /j~ ,1 1 _ / /
~.- I '1 EEPONSE3 AND Amc-"NTWME e<llsts MIE QA REu'-- - intEDI CU3miD', PLEASE E35UIRE AU. R tsaman r>> l
ca 96-is7s gjb Pc30 3 of Reactor Protective System (RPS) . Shape Annealing Factor Slope Disposition Condition: During performance of Reactor Engineering testing, the data for the shape Annealing Factor (SAF) produced unexpected results. For three RPS wide range channels (A, C and D) and one ' linear control channel (10) , the incore vs excore axial shape index had a negative slope. A positive slope is expected. I preliminary Root Causes:
- 1. The upper and lower uncompensated ion chamber inputs to the Nuclear Instrumentation cabinets were inadvertently swapped l during the design process. The swapped cables depiction on PC/M w 009-195 design drawings was a human ervar The design error was t detected during the verification process _ l
'#*' no \
l 2. The B channel RPS cabinet implementation resulted in the configuration being correct for channel B. The B channel was the only channel which had the detector replaced. It has been concluded that the Upper / Lower connectors have been reversed.
)
Drawing errors were not identified during implementation of the i PC/M. l f 3. It has been determined that Channel 9 is the affected channel l and channel 10 is connected properly. Channel 9 detector was . l J
/7\ replaced during this 1996 outage and the connections at the detector reversed. Therefore the connection at the RRS cabinet i i should be. reversed to provide proper operation using a temporary system alteration. Refer to the detailed review performed by 4
Reactor Engineering which is included in this CR. I Final root cause(s) are still under investigation. . Generic Implications:
- 1. , Unit 2 has been reviewed and it is concluded that this condition PC/M 008-285 did not revise
~
is not applicable. Unlike PSL-1, the PSL-2 linear channel connector identifiers. ="=r Therefore the inputs and conne_eters veret r.ho- :s bef cre =M implementation of the PC/M. Follow-up actions have been iderR.d ica ns Necessal'f). Also, the SAF results for
f i . ; i j CR 95-1878 g ] Pcg3 4 ef Unit 2 were reviewed by RE and no anomalies were present. 1 l 2. A review of.RPS/NI input and outputs was conducted s a result I i of CR 96-1787. No input / output discrepancies were identified. I i i
- . Non Conforaance 8tatement l Non conforming conditions concerning charcnel B has been corrected with the issuance of .CRN 009-195-6468. A verification of cable i
l designations is to be accomplished next outage (see Actions j Necessary). This verification is to determine any conditions l requiring correction. I i i f Mode Holds There are currently no mode holds. Actions Necessary
- 1. ! g 009-195-6468 has been prepared to correct the condition
] described in this report. Comp %rg / ! t j 2. An analysis of past operation to determine reportability is to { l } be prepared by Nuclear Fuels. Reportability is to be pre ar 96 I
'E l
by Licensing- COMPW (ATTAcJtED PA6es 20-38) 1 Rai w Engineering f;; cr ;1:ti... L e;3. Thi: will p fff'! i 3. IM.sM I;_a i i..;1 4e RPS and Control' Channel root cause(s) and methods for 1 h prevention; bg b '2.5 ConAgrt( Arnecya Mcts d-24) #Gggn l 4. Issue a PMAI to Engineering for the following. Verification J of drawings and as built configuration related to cable and detector designations is ongoing and to be completed by the i end of next respective U1 and U2 outage. This verification , j is to determipe any conditions requiring correction. SEE !M6.I !! P/MtIIr (0 A4i A 9[EL[9f. S. I.. .
'"'" '.;-ICM M reversk the connection of detector 9 I
upper /lowerinp@utsattheRRScabinetviaatemporarysy alterationOR .
- Mc FOM6#. '
TRAcfJtJG REAM ,
- 6. See page 7 for additional actions.
- l
i CR 96-1878 d Pcgo5of[36
~
Operability 8t'atement Based on the completion of this evaluation and CRN 009-195-6468, all the RPS Channels are operable. Loss of one RRS control ! channel and/or detector does not affect Tech Spec requirements. Therefore this is not an operability concern. See page 7 for l additional assessment of operability. Past RPS operability is to be addressed as detailed above in Actions Necessary. Conclusions
- 1. Mode Holds Imposed? Y No Yes
- 2. Revised Mode Holds? X No Yes
- 3. Operability Concern? Y No Yes Past operability under investigation
- 4. Actions Necessary No x Yes, see above Prepared r By: M- Date 8-2 -Pd r- y Verified By: fom,[c b 7)d Date 8f1. /90 Approved By: A -
e Date 8, ,6 1 l
. l i
i } CR# El [ i REACTOR ENGINEERING DISPOSITION i Backgranad } CRW 961373 was issued to evaluate the operability of Unit i RPS Channels A, C, D and Control Channel # 10 } ! Linear Range Detectors operability. Data taken during the Unit i Cycle 14 initial power ascension indicated that i these detectors measured core power moving to the top of the core durmg power ascension. This is an unexpecsed i phenomena and did not agree with the trend of power movag to the bonom of the core durmg the Unit i Cycle 14 initial power ascension indicated by RPS Channel B Linear Range Detector, Control Channel #9 Linear Range Detector and the BEACON Core Power Distribution Momsoring System. Evaluatina Based on evaluation of the data collected as part of the Shape Annealing Factor (SAF) test in accordance with Pre- i operanonal Test Procedure No. 3200093, Rev. 5 it was concluded that RPS Channels A, C, D Linear Range Detectors could have rolled leads of the top and bonom detector chambers input to the RPS drawers. l&C Engineering and !&C Maintenance were contacted to review the possibility of such a configuration due to the modifications performed during the refueling outage in accordance with PC/M 95009. I&C discovered an error in the PC/M design that could have led to rolled leads." L rsgex %. W l On 7/30/961&C Maintenance rolled the leads for RPS Channels A, C, D Linear Range Detectors and recalibrated f ASL Lead CEA Bank 7 was inserted to induce a core power shift to the bonom of the core to verify the correct configuration of the conneenon of the top and bonom detector chambers to the RPS for Channels A,B, C, D Linear Range Detectors. This test sonfirmed the proper configuration of the A,B, C, D Linear Range Detectors On 7/31/96 DVMs were connected to Control Channel Channels #9 and #10 Linear Range Detectors in accotdance I with Pre operanonal Test Procedure No. 3200093, Rev. 5 to verify the top and bonom detector chambers wiring contiguranonh CEA Bank 7 was inserted (as'part of the upcoming MTC test preparanons) and core power
~ \ f shined to the bonom of the core. The data collected during this test demonstrated that Control Chann
+ 6 Range Detector is wired correctly and Control Channel #9 Linear Range Detector isMed 6-ly. After a
[ l careful review of the Unit I Cycle 14 iistial power ascension data for Control Channel Channels #9 and # 10 Linear Range Detectors it was confirmed that Control Channel #10 Linear Range Detector is wired correctly and Control I Channel #9 Linear Range Detector is wired incorrectly. A computabon errer in the preliminary evalution resulted in the mistaken identification of Control Channel #10 Linear Range Detector as miswired. A review of the SAF test results for Unit 2 Cycle 9 was performed. No anomalies or unexpected results were found. Opernhdity RPS Channels A, B,C, D Linear Range Detectors have been restored to their proper conSguration. THERE IS NO OPERABILITY CONCERN REAG ARDING RPS CHANNELS A, B, C, D L11dAR RANGE DETECTORS. Control Channels # 9 and # 10 Linear Range Detectors are Not Nuclear Safety Related used as input to the Reactor Regulating System and chart recorder JR 012. Chart recorder JR412'is used to verify compliance with ASI limits of Technical Specification 3.2.1 and 3.2.5. AS A RESULT CONTROL CHANNEL #9 LINEAR RANGE DETECTOR AND CHART RECORDER JR 012 SHOULD BE CONSIDERED OUT OF SERVICE UNTIL THE PROPER WIRING CONFJGURATION IS IMPLEMENTED.
.._ .__ . _ _ . . - . . _ _ _ _ _ _ . . _ . . _ _ _ - . _ . . _ _ _ .. _ . . . . _..._mm._ .
J W I ' CRA 961878 Page7e d i
- Required Actinas 4
- 1. Place Control Channel #9 Linear Range Detector and chart recorder JR.012 out of service until the proper wiring configuranon is implemented. wWO gs'gf '
< 2. Use Control Channel #10 Linear Range Detector only for input to abe Reactor Regulating System until the proper wiring configuration is implemented for Control Channe! #9 Linear Range Detector. CawytB g
- 3. Use the average of ASI indicated from RPS Channels A, B, C, D Linear Range Detectors to verify I compliance with ASI limits of Techmcal Specificanon 3.2.1 and 3.2.5 until the proper wiring configuranon is implemented for Control Channel #9 Linear Range Detector. gpg
}
- Prepared by
- No N Date: I 4
! verised by: de ziwl/ ' osie: 54Irz
//
i i . i I i i e i d i i j j 4
CR 961878 Page.6,d.33
\
) i )
)
NUCLEAR INSTRUMENTATION
- UPPER / LOWER LINEAR DETECTOR CABLE SWAP :
ROOT CAUSE ANALYSIS AND CORRECTIVE ACTIONS i l 4 i l August 1996 Prepared by: _ Prepared by: MIMI For additional information, contact Warren Busch x7484 1
i .
- CR EMS l Page,9,of,,33' 1
! NUCLEAR INSTRUMENTATION UPPER / LOWER LINEAR DETECTOR CABLE ! SWAP - I ROOT CAUSE ANALYSIS AND CORRECTIVE ACTIONS i t j. ! CONTENTS i I Background II Root Cause Method Overview 1 III Design Error Characterization j IV Es(wdog Venfication Process Review i V Post Modification Testing Review . VI Connector Swap at Detectors 6 & 9 1
. VII ASI Root Cause Evaluation l VIII Conclusions IX Design Error Barner Analysis Matrix .t . X Detector Connector Barrier Analysis Matrix .
D XI ASI Barrier Analysis Matrix ! A ; I. BACKGROUND o On July 30,1996, St. Lucie Unit 1 was operating at approximately 100% reactor power. I Power ascension from an extended refueling outage was completed on the previous day. j 7 g Reactor Engineering was prepanng data collected from performance of pre-operstional test , gd procedure 3200093, Shape Annealing Factor Test. The data taken dunng power ascension 9 indicated that power flux at the bottom of the core for Reactor Protective System (RPS)
- Channels A, C & D and Reactor Regulating System (RRS) Control Channel 10 had decreased M for increasing power levels. This is contrary to an expected increase in lower core power hLg flux, as was indicated by RPS Channel C and RRS Control Channel 9.
1-0 The tnethod in which the data was taken and reduced was reviewed. The drawings associated 3 j,3 with PCM 009-195, RPS NI Drawer Replacement, were reviewed. Based on the drawing review, it was concluded t'a.t the PCM coarniaad a desian error and depicted the lower
'a ,A uncomp'Eted e ion chamber going to the upper ion chambeTmput for NI channels A, B , C and and theDA,at theD RPS C and NI Drawer in declared channels were the control room.
out of service. A Condition NI channel IFindicatingReport the was yA a erpa *~i trend was attributed to the PCM implementation and detector replacenacpt.N channel was the only NI channel which had the detector replaced dunng the outage. M 8@hl@ p~ A chans pt nonce to the PCM was prepared and the upper and lower ion chacoer inputs n - A, C, and D drawers were reversed. Rod insertions were used to verify the expeo. ~ al response after the modification. 2
CR 961878 Page .[g_ et 33, i
- l. ,6
- It was subsequently determined that Control channel 9, which also had its detector replaced i during the outage as a coincident Maintenance activity, had its cables reversed at the detector.
The initial indication that control channel 9 was indicating the correct trend and control 1
, channel 10 was inverted was due to the Shape Annealing Factor Test setup. Detector 9 was
!* taken out of service. tion to vent described above, two additional design errors we uring f' i /[ implementation of PC/M 009-195. Condition Report (CR) %1434 identifies that wires were [ s p smaller than assumed in the design r=*ine in e===ive dron. CR %1787 identified a l Wition where a relay function for the RCS low flow setpoint to the RPS was not provided l m, resulting in a constant low flow trip situation.
~
[ \ "~ ~ . _ _ . .._...
- H. ROOT CAUSE METHOD OVERVIEN I
The two design errors described in CR's %1434 and %1787 were detected as part of the PC/M implementation. B$nf *** d>=p ~~ =ere made dunng preparation of_ j equipment specification,s/ The root cause of the errors was attributed to the preparation of j nit I documents with the assumption of similarity between units 1 and 2.JNo further i jdes J dicreause for these two design errors are included in this document hoWever, generic implementations and corrective actions are addressed in appropriate sections. l f l ! Y #,The method barrier analysis. This chosen method wasto determme chosen rootcondition because the overall cause(s) of the was considered to beswapp
, process related and several barriers which failed could easily be identified.
l 1 l 1 Two problem statements are developed. The first one is associated with the design error, the i second is associated with the inadvertent wiring swap at the detectors on NI channel B and I control channel 9. Overlap may occur in the area of detection of the adverse condition (s) but the differences in the applicable processes warrants separate investigation. The following problem statements have been established:
'Ibe PC/M for the NI drawer replacement contained a design error which was not detected until full power operation.
The replacement of the NI channel B and control channel 9 UIC detectors resulted in swapped lower and upper detector cables which was not detected until full power operation. The targets for the bamer analysis are essentially the converse of the problem statements. The root cause analysis for why ASI deviations were not detected during startup are addressed in Section VII. 3
C R M.187s l Page,llof,{$ l The barriers, barrier assessments, root cause(s) for barrier failure, contributing factors, and j corrective actions are detailed on included matrices. IIL DESIGN ERROR CHARACTERIZATION The circumstances of the initial design error which depicted the upper UIC co ted to the l lower UIC input at the NI drawer was determined based on interviews. igner and l
- 1. mad Engineer interpreted conflicting information on the existing CWD- made an i assumption. The assumption was that the cable identified on the CWD as " BOT SIG" feeding l
" Signal 2 (Subchannel B)" was the lower detector.
j l The assumptions was based somewhat on the CWDs for Unit 2 which besides the two j identifiers above have a connector . identifier as "L". Tlic Unit 2' drawings wereused'Inngte l certain extent by thi! Designer in preparation of the Udit 1 dawings. ThTet 2 drawass4 also contamM confHetian inforco. tion in that the lower detector 7hamher caaaae'ad to tW l - ch mh.cre :. ufn additioit6e "Subchannel A" designator being the up%K
/' chamber input on Unit 2. angi _thAewer chamber input on Unit 1 a difference in the U1 ab j
/ _
U2 existing design. 'Ibe Unit 2 drawers were walked down and are wired at the control room !4 end in accordance with the CWD's. 'Ibe ASI data for Unit 2 was reviewed and confirmed that I/ the correct response is obtained. The acceptability of the U2 configuration is based on the NI PC/M implementation, specific corrective action for Unit 2 is identified in the CR %1878 l
- response.
The apparent conflicting information on the drawing is that the cable marked " BOT SIG", l i " Signal 2 (Subchannel B)", and "L" for U2 is shown going to the upper section of the j detector. This is due to the original detectors being installed where the BOTTOM detector is j actually the upper chamber and the TOP detector is actually the lower chambe Tha FQ be supplied with cable connections at the top or bottom of the detecto CE design otsty j l t j JLucie requires the cable connections on the bottom of the detector.b_ Designer did not nav
- a complete understanding of this detail.
1 I j The lack of questioning attitude given the conflicting information is identified as a weakness. IV. ENGINEERING VERIFICATION PROCESS REVIEW The verification process for PC/M 009-195 was performed in the following manner and in the following sequence: i The drawings were prepared by the Lead Designer with input from the Lead Engineer. The l drawings were then checked by a second Designer. The Designer had no special knowledge in l NI design. This drawing check was essentially a drafting check, considering overall format and consistency between FPL issued drawings. The drawings were then reviewed and approved by the Lead Engineer and then by the Engineering Supervisor. 4
CR 96-1875 i hee .!.!-d.lf i The Engineering Package was prepared by the Is.ad Engineer. The verification performed by i a second Engineer did not include a point to point wiring check on the drawings. Final vaadar
- i documentation was not available, the drawings had already haan Renad mad the ganaralf j wmation was made that the U1 drawings were similar to the U2 drawings, j .W f i -The final vendor documentation was issued approximately 2 months later under CRN ya l )p# <S 3 @ third Engineer and verified by a fourth Engineer. Issuance of the documents did no melude a
! O review of previously issued design documents.
/ The method and sequence of verification described above apnaars to maar the reauirements set g forth in OI 1.7. Desian input / Verification. Howevergmethod used is identified as a
~ wea kness mad caneriairaa a weakness in QI 1.7. 'Ibe drawings were not point to point verified 6%mpetent individual who remamed mdependent of the design process. A more robust verification process would have required the verifying Engineer to sign each of the drawings 8y as an independent verifier as well as the overall Engineering Package. The use of four p different verifiers / checkers for the various documents resulted in lack of a single individual with an overall verification plan or understanding.
1 An additional weakness is identified in the amount of time available to the verifying Faeinaars to perform verification. The total U1 project man-hours through May 1996 was appronmately h 1150 man-hours. For scoping and scheduling purposes on a critical complex project,30% of _ e n projects total man-hours should be allocated for verification activities. This should have g-accounted for a few hundred. man-hours. .The verifying Engineer on the Engineering Package 34, charged a total of 40 man-hours to the project,15% were on overtime. The ver#ng , 7 incer on the CRN_ charged a enent of 6 hours to the project. Thi:, relatively small amount of time sFnt on verification is due to project delays due to suppornng unanricipated outages, the number of large projects being worked coincidently in PEG I&C (4 during January and February '%) and the available resources (equivalent to 2.5 Engineers). V. POST MODIFICATION TESTING REVIEW The post modification testing for PC/M 009195 is summeriud as follows: Section 2.9 Insulation resistance, detector pressure, pre-energization, and start-up test (using vendor supplied procedures) is to be performed. Section 2.14 Start-up and functional testing on new drawers to verify proper operation. Perform functional test of all outputs from RPS NI drawer (annun, meters, recorders, etc.) Section 3.0 The NI system shall be subjected to a test in accordance with I&C procedures and Vendor procedures. 5 l
i' CR M 1878 j Page ,,13 d M i The post modification testing failed to identify the linear cable connections as a cr'itical input I
- needing functional verification. The recommanded post modification testing was based on the assumption of similarity between Unit 1 and Unit 2 and successful implementation on Unit 2.
{ -. , } The post modification testing procedure was also based on the Unit 2 procedure. The lack of
, < identifying the critical characteristics in the engineering package or the post modification
~
testing isMentified as a weakness. ) l h hS# VI. CONNECTOR SWAP AT DETECTORS N 6 l l 1 Coincident with implementation of PC/M 009-195, two linear channel Uncompensated Ion l Chambers were replaced as a maintenance activity. The detectors were replaced W= of ~ j the age of the detectors. Durmg connection of the detector pigtails to the field cables, the i J connections were inadvertently reversed for the upper and lower detector chambers. l The causal factor for the swap was that the detector was supplied with pigtail labeling which differed from the existing detectors. The existing detectors were labeled " TOP SIG" and
" BOT SIG" as discussed previously. The new detectors were supplied labeled "A" and "B". l The replacement detectors were supplied through ABB/CE under a PC-1 purchase order as l being identical to the existing detectors. ABB/CE and the detector manufacturer, Imaging & !
Sensing Technology, were contacted. A similar occurrence occurred at Calven Cliffs. I
- ABB/CE issued a corrective action report in accordance with their procedures and is I investigating root cause of the difference between the detectors. The FPL Quality Assurance l program is responsible for monitoring the perform =e of approved vendors for PC-1 materials. This process did not identify weaknesses with these vendors in this area. l ICM)partment had several opportunities to identify the discrepancies but failed to do so.
@ % "ures for detector checkout and installation referred to the existing cable tagging. The decision how to connect the cables did not identify potential affects on controlled plant drawings. The lack of detailed design information and apparent inconsistencies on the controlled drawings contributed. The failure to identify the differences between the procedures and the supplied detectors is identified as a weakneu.
l l VII.ASI ROOT CAUSE EVALUATION EVALUATION This section of the root cause evaluation focuses on the failure to detect the design error and maintenance error earlier during the Unit 1 Cycle 14 initial power ascension. The wiring error was discovered by Reactor Engmeering (RE) a day after reaching full power when the SAF test data was under evaluation. 6 j
l l i CR Elm
- j. Pap, lid.dj
!* Personnel Interviews j Personnel interviews or personal observation forms were completed for the available personnel !- on duty during the initial power ascension. A summary of their observations follows:
- 1. 12 of the 21 of the operators and RE personnel on shift were available for
! interview. 6 of those interviewed noted or were involved in discussions l regarding any anomalies with the RPS I.inaar Power Range Detectors during ! power ascension or immediately after. ,' 2. The Operations and RE personnel noting or discussing the anomaly accepted l that the_B channel detector may behave strangely since it was replaced. ) 3. The first observation of anomalous RPS Linear Power Range Detector behavior l was on 7/25/% when in MODE 2 below 5% power when Channel B was noted j to be reading high. [This was explained as expected behavior and a low power j calibration corrected the concern until 13 % power at which time Channel B was
- put in bypass until the 25% power calibration. CR# 96-1818 addressed this issue.]
i l 4. On 7/25/% power was increased to 5.5% by withdrawing CEA's from about 90 1 - l to 103 inches. ASI for channels A, C, D all went to the bonom (the top of the ' ! core) as indicated (and expected) on the LPD meters on RTGB-104. Only l channel B went to the top of the meter (the bonom of the core). 7his was
- questioned by the NPS and the RO's. The explanation provided by RE was that channel B was a new detector. It had not been fully calibrated, and that it had i conservative gains set. So channel B was going to show some strange
! indications. i
- 5. The next observation of anomalous RPS Linear Power Range Detector behavior i was on 7/28/% when increasing power from the 70% plateau to the 98%
- plateau. RE representative question regarding differences between RPS channel l B reading compared to channels A, C and D readings. The RE representative responded with
- ASI values were within Technical specification limits. SAF
- test was being performed to calibrate B channel because it was a new detector.
j' 6. The next observation of anomalous RPS Linear Power Range Detector behavior i was on 7/30/% after reaching 100% power on 7/29/% and after the SAF data j was evaluated by RE and the wiring error was subsequently discovered. l
- External Influences I.ow power CEA movement impact on ASI results in difficult to ascertain trends due to the changing reactivity effects of an MTC changmg from positive to negative, changing power level, T changes and poorer calibration accuracy due to low flux levels.
7
4 CR 41878 Pase y,ef,ij j~ ASI control is not an important factor in a xenon free initial startup. In addition the SAF test j requires the ASI to be allowed to drift (with no tight controls) to get a wide range of ASI 4 values. l- The concerns regarding RPS Channel B Linear Power Range Detector udnown behavior due
- to replacement reinforce a perception of expected anomalous behavior.
l Relatively frequent ASI calibration of the Linear Power Range Detectors make it difficult to observe a trend. Past ASI experience with initial startup reinforces that ASI is well behaved and requires no l i special attention. Slow power ramp rate results in gradual ASI changes making trends more difficult to recognize. i The BEACON Core Monitoring System provides an easily accessible ASI based on Incore I detectors that trends core ASI behavior. i Barrier Analysis l l The root cause evaluation technique used is a retrospective barrier analytis. This technique i evaluates the barriers that existed during power ascension that could have correctly identified 4 the wiring error earlier in the power ascension. The attached table presents the results of this Control Barrier Analysis. j ! CONCLUSION i Prior to significant power levels it is difficult to detect the discrepancies in RPS ASI trends l
- caused by the design error. Although ASI was monitored to verify compliance with the Tachaical Specification limits, the power ascension startup testing program didn't identify l discrepant trends in RPS ASI until after full powe; operation was reached. The initial cycle j' startup power ascension program doesn't require specific ASI control and consequently, ASI
- trending to assure a target ASI is achieved is not required. Nevertheless, during the power l ascension operators idennfied and RPS ASI discrepancy between Safety Channel B and Safety j Channels A,C, and D. Resolution of this discrepancy at that time failed to identify the design error. This was due to a belief that the identified difference between Channel B relative to Channels A.C and D was due to the recent Channel B detector replacement.
l j The root causes contributmg to the failure to identify the anoma!aus RPS Linear Power Range j Detector behavior as a wtring error early during initial power ascension can be classified in three major categories. These are: Inndeannte PMT Both the RPS NI Drawer Replacement PC/M (95009) and the Linear Power Range Detector replacement failed to identify ASI response and trending during power ascension or specific 8
4
- CR 51878 j Pagejf.et.g testing with CEA insertion at a low power level (around 25 %). Such testing would have j identified expected response and acceptance criteria that would have revealed the wiring error, a i i
j Poor Procedural ASI Guidane ;
- A target ESI is not required during initial startup. Current practice for developing a target ESI sliding (with power) curve uses a measured to predicted bias that is deternuned at HFP l equilibrium conditions. Nevertheless, a target ESI sliding curve can be preliminarily i l
j established at the 25% power plateau using the aged to predicted bias determined at that power. l i 1
- Poor Work Practice . .. . . . __
l 9 l Self checking of the SAF test data collected was not performed to assure the quality and l expected trend of the data. Real time data reduction and trending of the SAF data would have i revealed the Linear Power Range Detector wtrmg error earlier in the initial power ascension. Throughout an operating cycle Operations or RE will plot RPS ASI(average of four channels) and manage to a target ESI during power maneuvers l However this practice is not employed i during initial startups
- Trending the initial performance of instruments or equipment that has been subject to major l modification, maintenance or replacement is a good work practice that would have revealed
- the Linear Power Range Detector wtrmg error earlier in the initial power ascension. l t
! The Operations and Reactor Engineering personnel displayed an insufficiently robust l questioning attitude to thoroughly investigate the earlier observed (70% to 85% power) 1 anomalies with the Linear Power Range Detectors. Although Operators expressed a concern and provided supporting observed facts, it was not effective. Reactor Engineering didn't f effectively draw out and address the specifics of the expressed concern. The control room j { crew's teamwork broke down in the area of Conflict Resolution and was unable to satisfactorily answer the questions of all parties involved. l 4 RECOMMENDFD CORRECTIVE ACTION
- 1. Revise Pre-OP 3200092, " Reactor Engineering Power Ascension Program," to require establishment of a target ESI sliding curve at the 25% plateau.
- 2. Revise Pre-OP 3200093, "SAF Test," to require real time data reduction and trending of the SAF data early during the test to assure the quality of the data collected.
- 3. Provide traimng to the Operations and Reactor Engineering departments regarding robust questioning attitude to thoroughly investigate the early observed anomalies.
9
. -~ - . - . - . . . - - . - - . - - - - - - . - . . . - . - - . . - ,
i"- CR 96 ts7s Page12,et,1$ l . 4. Establish Reactor Engineering as the petformance monitoring engineers for core I 1 monitoring instranentation. _ . - 1 . . . . . .
- VM. CONCLUSIONS l
The following action items have been identified to correct the conditions and prevent re-occurrence. The action items cover the identified root causes and weaknesses for the detector cable swaps at the drawers and at the detectors, the lack of detection of the condition until full j power, and the design errors addressed in CR's 96-1434 and 96-1787. 4 Cause Corrective Action Implementation Caartwas information on ensung Walkdown. retag, correct drawings (1) PMAX to ENG U1,5/30/97 OY plant drawings for linear detector as necessary at fint omages of . cables. sufficient duranon (2) PMAI to ENG - U2,12/15/97
. Revise Q11.7 to regare (3) PMAI to ENG - 9/30/96 Independent Verificauco not performed on drawings. =
' detwadaar veri 6er manamre on 71 '
safety relased drawings.
-y ,tsview previously prepared Safety {4) PMAI to ENG - 10/31/96 g1 talated IAC and Elset. PCMs ;
Assumpoon of similarity between Revise QI 1.7 to idennfy the same level of vertficanon is reqmrod on (3) PMAI to ENG 9/30/96 g:c units duplicate packages. Lack of quesuomng animde durms Provide nonficanon of event and Completed - Presentation given design process espectauces to personnel g/7/96 PMT did not identify linear Revise QI 1.1 to reqmre criocal (3) PMAI to ENG 9/30/96 connections as critical aspect to be funcnons for PMT be idennfied in M", demonstrated Safery Related EP's lasufficies time alloned for Work control process changes and No specific tracking required, y #~
" verificance reorgamzation Detectors supplied with different ABB/CE invesugaung and will No specific tracking required.
cable tagging as equivalent issue a Techmcal Bulleen in Will be evaluated under the accordance with their procedures. normal FOP processes. Differences between detectors not ICM to provide aannmaaa of (5) PMAl to ICM . 9/30/96 73 idenafied 'ay ICM event and erparranans to personnel Q ' SAF data was not evaluated during Require real time SAF data (6) PMAI to Reactor Eng - g3Z, ; power ascension evaluation 1/15/97 Provide target ESis for Power (7) PMAI to Reactor Eng - SW ASI behavior was not clearly identified to the Control Ascension Program 1/15/97 Room Crew No one acer==r=hle for encore RE to snoniter perfortnance of core (8) PMAI to Reactor Eng - 7,9 l detector performance motutoring instruments 10/31/96 10
1 CR 96.I878 l Pase)).etM Cause Correcthe Action Impg 3 / of4m Perd an Operations training (9) PMAI to Traimag - 10/31/96 2 ASI-{ ..gf wasinadequase brief regardag dds W i b . i in addidon to the conective actions idenufied above (9 PMAls) , this root cause analysis is being sent to Turkey j Point Engmeering and the Quality Assurance for review and any further acuan. 4 4 6 4 4 i 9 11
l . . CR 96-1878 , Page B _of.3 6 l IX. Design Error Barrier Analysis Matrix
/
( *
\
Assessment Centrhuting Facters Cornetive Action Consequences Barrien Humaa Errer was made coupled with a Conflicting desiya information on existing Walkdown. tagging. and J.. , PC/M drawing Design Process latent condition. The U2 drawings on plant drawings. corrections will be made at the next incorrectly shows ; oportunin. I upper chamber wired g which the UI design was based I contained an error. Similarity between Drawing revisions (labeling) not l to lower electronics ' Provide notification of event and i the units was assumed. drawing w.. .J . lve. and lower chamber capectations to Engmeering wired to upper conflicts not identified and resolved. r Assumed similarity between units. personnel. Completed SU/96. electronics & wasn't discovered until 100% power IV did not include point to point Assumed similarity between enits. Revise QI s in the following areas:
, Independent '
' ' ' verification of drawings. Verification signanwe i-: , - - - = =
verification (IV) ~ on Safety Related drawings andlevel 'y # I Verificationtchecking of parts done by ' Weaknesses in the Engineering Ql's of verification on duplicate packages; , l4 different individuals. No overall '
- p \I.Dgc understanding of verification by any one individualinvolved. Not enough Compressed schedule due to extended back to back outages. Review open IAC/Elec PC/Ms.
time allotted for verification.M Pbst Modificatior[ ' PMT failed to identify linear detector Assurned similarity between units. Revise Ql's to require identification i Testing (PMT) connections as critical function. UI - of critical functions to be ;
' Lead Engineer and 1. cad ICM &, ; " i dennonstrated during PMT in Safety PMT based on U2 procedure. - s Experienced perso mel. nee-not involv left company prior to PMT. Related EP's.
f
\ in PMT process. -
E \ d k I
.- . . _ . - . . - . . . . - - - . - . - - - . . . . - ..- . . . . _ - . - . . - ~ . _ . - . _ . . - . . . -.
CR 96-1878 Page Zoer.3 $ ' X. Detector Connector Barrier Analysis Matrix CentrNeting Factors Cwemee Action Barriers Assessment Cn_ :ws Root cause(s) under investigation by ABB/CE issued Corrective Actson PC.I Vendor Detectors were supplied with cables Replacement of the N1 Report, will issue a techairal bulletin labeled different than existing detectors. ABB/CE Channel B and control Certificiation of aber root cause determination. l channel 9 detectors equivalence No deviation notices or revised i Techairst Bulletin will be headled in resulted in reversed drawings were supplied. accordance with normal prare==ce. ,. lower and upper ! cables which was not g detected until full , 4 power operation , ,qbT g y- . Notify ICM gia: of event and Detector checkout Procedure identified cables tagged expectations with regard to potential procedure differently it.an new detector, not devittions. identified for corrective action Differences between tagging, potential Inconsistent information on plant drawings Notify ICM m_: of event and Detector expectations with regard to poecatisi installation affect of cable tag differences on plant drawings not identified. deviations.
/l - - --
a A Amm ..a-J_.& m.- .7- _,)R._J-L -.1-E-- *a- - '
#- 4a,m-JJ 44 . eaAwaA % a .da- -~ 4& L K. d-m--*T-J*- 5 as 4,a sh-a z AmaMa.. aam-+4 4
00 m
.1 O s;'
- 7 gk w O e b k
aa i i U l r 5 t i i v
~
W J
\
LO 4
<t .
D-1 4
CR wat h ee 3 L et L , XI. ASI BARRIER ANALYSIS MATRIX Control Barrier Analysis Worksheet Root Cause Centreuters Barriers Barrier Assessment Ce I%cus is os CEAs for ASI Provides guede=re to ASI guidance is deferred to ASI anomaly, due to upper OP 3200021,
- ASI control and Xence effects above control withis allowalde preop 3200092 for initial and lower detector Control" 50% power. ESI not provided bands to a target ESI vs startup.
chambers reversed, not for initial startup. identified during initial power starting at 25% power. RE can supersede power ascension. with wrnten or verbal guidance Requires a trend ' plot of ASI only when 2 - , - '---- at seeady state conditions. ESI is not - provided for initial startup and ASI guidance is g deferred to PrcOP 3200092. i Provides power escalation Refers to OP 3200021 for Focus is on CEAs for ASI OP t-0030123,
- Reactor guidance and is _____:r t details of ASI control which control and Xenon effects above Operating Guidelines 50% power.
CEAs above teng Term &fers to preop 3200092. . During Steady State and Scheduled lead Changes" Steady State Limits and inserted enough (102*) to begin controlling ASI between 20% to 50% power. Refers to OP 3200021 for specific ASI instructions. Provides , guidance to control ASI ' with CEAs above 50% power. .. 9 >
~
i 1
CR 96-1878 Page Z$_ of _33 XI. ASI BARRIER ANALYSIS MATRIX Control Barrie.- Analysis Worksheet Barrier Assessment Root Caisse ContrButors Consequences Barriers preop 3200092. " Reactor increases power in No specific ASI guidance 1. CEAs at 122" to 137.* accordance with OP I- er ESI target is provided. withdrawn and not used for ASI Engineering Power control through most of the Ascension Program" 0030123. Note provides that slow ramp up in power power ascension. 2. Note in shouldn't result in ASI
,M, e and previous transients with the ESI experience reinforces that ASI nearly achieved throughout is not a concern. -
the ascension. Refers the 3. No ESI provided on initial op:tetors to RE for startup. 4. Measured to - additional guidance on ASI predicted ASI bias not known at control. Initial startup .4. Frequent ASI calibrations of detectors taask easy recognition of a problem. Requires a once per shift No regiirement to trend Would not catch an unexpected OP I 0010125. " Schedule of Periodic Tests, Checks check to verify that ASIis ASI. trend as long as the DNB AST and Calibrations" with the Tech Spec ifO limit is satisfied. limits per OP 14)l10057. OSP 64.01, " Reactor Provides for the ASI No requirement to record No as found acceptance criteria Engineering Periodic Tests, calibration of the Linear as found values. is specified to assure actual Checks and Calibrations
- Power Range Detectors to instrument accuracy is the BEACON Core performing within the bounds Monitoring ASI(Inc. ire assumed in the safety analysis, detectors).
Operations records, bourly. No requirement to trend No requirement to trend or Electronic recordmg device the RPS ASI readings for data. evaluate ASI. makes it more difficult to see a all four channels. trend. PMT for N! Drawer PC/M No requirements for full No functional test specified Modification, expected behavior 95009 functional test of interfaces to fully verify detector and any need for functional when returned to service. interface with RPS. checkout of ASI behavior not communicated to Control Room crew. 2
T i I ! Ca w.is7: ! i Pese W _ et 3 8 ! XI. ASI BARRIER ANALYSIS MATRIX , l i Control Barrier Analysis Worksheet Rest Cause Centreusers Consequence Barriers N Berrier AW l No requirements for full No functional test specified Ma W ewd behavior PMT for Linear Range and any need for functional I functional test of interfaces to fully verify detector Detector Replacement checkoutof ASIbehavioract when retmined to service. connected properly, comununicased to Control Room w crew. No requirement to reduce 1. Extensive data redaction has SAF test casa collected No .-:;- ' :== to reduce and evaluate data until the takes up to a month to complete every % hour. and evaluese data until the completion of the test aner in the past. 2. Unileed resource completion of the test aher scheduled for daea colleedse l 100% power achieved. 100% power achieved. only. 3. Requirensest to Data was reduced and evaluated more quickly than perform test lays a bases for the ; in the past.
-i : of expected '
h behavior of ASI. ; Removes focus fross I. Trending RPS ASI not ! BEACON display of core Provides graphic real thne display of core ASI for the trending ASI with the RPS. required. 2. I'wus is on core peripheral ASI. behavior not RPC behavior. l past 24 hours as -- - -d I by the Iftcore detectors. - l f I f t I i i
?
9 3 l
l CR 96-1878 f Page g d 3 8 XI. ASI BARRIER ANALYSIS MATRIX Control Barrier Analysis Worksheet Barrier Assemment Root Caine CentrRMuters Ceasequences Barriers No review of RPS ASI and Lack of an aggressive 1. Focus is on core behavior RE Test Engineers on shift SAF data performed during questioning attitude. and not RPS behavior. 2. observation and questioning power ascension. Too Insufficient knowledge of the attitude. readily accepted the easy expectations of the results of esplanation for -different" I imear Range Detector behavior of Channel B of replacenient and PC/M on RPS the RPS. measured ASI. 3. Failed to effectively question Operations , as to the specifics of the 1 anomaly noted. 4. Data - gatherug and setup extensive , plateau activities kept RE w@J. 5. Slow ratnp raec resuhed in hard to dis 6ern gradual trends in ASI.' 6.' Frequent ASI calibrations of detectors mask casy recognition of a problem. ' e i 0 4
CR 96-1878 F'St N *t 5 XI. ASI BARRIER ANALYSIS MATRIX Contrd Barrier Andysis Worksheet a-ser Amemament Rest Cause CentetWws C.n.e,.e.eu Ismem Weak Control Rocas teest 1. Umfandliarky wkh SAF. Operations ce shift Anomalous ASI behavior questioned during ascension conflict resolutloa. Proceduraldeference so RE on observation and questioning froni 70% power to 98%. ASIissues. 2. Faded so attitude. Failed to continue to eTM.di communicase so RE the specifics ofIbe anomaly question to a satisfactory answer that was thoroughly noted. 3. E=W an unknown understood behavior of CW n Limear Range Detector due to replacement.4. Slow ramp rase resuleed in hard to descera gradual trends in ASt. S. Frequent ASI calibrations of
% mask easy recognition of a problem. 6. Observation of anomalous behavior at low power levels (<25%) was difncuk wkh several changing condklons (Tin, CEAs, power, calibrations).
5
U
,q e
i ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE INFORMATION RE0VIRED TO BE AVAILABLE FOR ENFORCEMENT PRE-PANEL PREPARED BY: Mark S. Miller NOTE: The Section Chief is responsible for preparation of this questionnaire and
- its distribution to attendees prior to an Enforcement Panel. (This information "
will be used by EICS to prepare the enforcement letter and Notice, as well as the transmittal memo to the Office of Enforcement explaining and justifying the
- Region's proposed escalated enforcement action.)
- 1. Facility: St. Lucie
, Unit: 1 l Docket Nos: 50-335
- License Nos
- DPR-67 Inspection Dates: July 2 - Auaust 28. 1995 Lead Inspector: Richard L. Prevatte
- 2. Check appropriate boxes:
[X] A Notice of Violation (without "boilerplate") which includes the recommended severity level for the violation is enclosed. [] This Notice has been reviewed by the Branch Chief or Division i Director and each violation includes the appropriate level of I specificity as to how and when the requirement was' violated. [] Copies of applicable Technical Specifications or license conditions
. cited in the Notice are enclosed.
- 3. Identify the reference to the Enforcement Policy Supplement (s) that best fits the violation (s) (e.g., Supplement I.C.2)
I.B.1' I .C.2. (bf I.C.6* I
- As stated in new enforcement policy
- 4. What is the apparent root cause of the violation or problem?
Personnel error in maintenance combined with a failure to perform adeauate post-maintenance testina and a failure to provide adeauate acceDtance criteria for surveillance testina of PORVs. Q vh
Me
- 5. State the message that should be given to the licensee (and industry) through this enforcement action.
Post-maintenance and surveillance testina should be of sufficient scope, and acceptance criteria of sufficient technical riaor, to ensure component operability.
- 6. Factual information related to the following civil penalty escalation or mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.):
- a. IDENTIFICATION: (Who identified the violation? What were the facts and circumstances related to the discovery of the violation? Was it self-disclosing? Was it identified as a result of a generic notification?)
The condition was identified by control room operators when it was noted that operation of the PORVs durina surveillance testina did not result in eXDected chanaes in RCS and auench tank parameters. The identification of the misalianed main disk quide was identified by the licensee when the valves were removed from the system for inspection. Failure to perform adeauate post-maintenance and surveillance testina was identified by the licensee in course of a riaorous root cause effort,
- b. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, describe preliminary information obtained during the inspection and exit ;
interview. l i The discrepant conditions were corrected by the licensee. See attachment. i What were the immediate corrective actions taken upon discovery of ; the violation, the development and implementation of long-term i corrective action and the timeliness of corrective actions? The PORVs were declared inoDerable, the unit Was Dlaced in a , condition not reauirina their operability and then was cooled down and depressurized. l Immediate corrective actions were appropriate l and the subject failures were investicated aaoressively. Short term corrective actionr. included DroDerly assemblina and testino the subject PORVs. addina a OC hold point to the PORV maintenance procedure to insure proper disc auide installation and to reauire a bench lift test under air pressure. Additionally, the licensee i chanaed the acceptance criteria in the PORV surveillance testina i procedure reauirina documentation of RCS pressure chance. PORV tailpine temperature chanae, and auench tank pressure, level and temperature changes. What was the degree of licensee initiative to address the violation and the adequacy of root cause analysis?
c ; TD > E : Root cause determination was well-coordinated. timely, and ! comprehensive. !
-c. LICENSEE PERFORMANCE: This factor takes into account the last two years or the period within the last two inspections, whichever is longer. ;
List past violations that may be related to the current violation ; (include specific requirement cited and the date issued): No violations involvina the adeouacy of post-maintenance testina
' hava been issued in the last two years.
Identify the applicable SALP category, the rating for this category. and the overall rating for the last two SALP periods, as wt 11 as any trend indicated: . The subject functional area is Maintenance and Surveillance, which ; was most recently rated SALP 1 (January 94). The previous SALP period, the area was rated a SALP 1.
- d. PRIOR OPPORTUNITY TO IDENTIFY: Were there opportunities ~ for the.
licensee to discover the violation sooner such as through normal surveillances, audits, QA activities, specific NRC or industry. notification, or reports by employees? Proper co;t-maintenance testina would have been effective in identifyina the inoperable status of the PORVs. Additionally. ! adeauate surveillance testina would have detected the inoperabit ity.
-The crior opportunities to identifiv the subject conditions is at the heart of this enforcement action.
- e. MULTIPLE OCCURRENCES: Were there multiple examples of the violation identified during this inspection? If there were, identify the number of examples and briefly describe each one.
Multiple occurrences have not been identified, except to the extent
-that the noted test failures applied to two PORVs.
- f. QQRATION: How long did the violation exist?
Since November 1994. l i l
, m,. - - , - ,
-u - - , , * -
s o ADDITIONAL COMMENTS / NOTES: See attached descriDtion of the subiect events. Note that, in addition to violations relatina to post-maintenance and surveillance testina adeauacY, a violation of TS 3.4.13, regardina PORV operability for LTOP, existed. The information in this document is current as of Auaust 22, 1995. 4 4 i
s - e ESCALATION AND MITIGATION FACTORS (57 FR 5791, February 18, 1992) 1 IDENTIFICATION CORRECTIVE LICENSEE PRIOR NJLTIPLE DURATION l ACTION PERFORMANCE OPPORTUNITY TO Oct1RRENCES IDENTIFY
+/- 50% +/ 50% +/ 100% + 100% + 100% + 100%
Licensee Timoliness of Current Licensee should Multiple used for identified (M) corrective violation is an have identified examples of significant j [To be applied action (M) isolated violation violation regulatory even if [Did NRC have failure that is sooner as a identified message to licensee could to intervene to inconsistent result of prior during licensee. (E) I have acconplish with licensee's opportunities inspection l identified the satisfactory good such as audits (only for SL 1, l violation short term or perfor aance (M) (E) II or III ' sooner) remedial action violations) (E) (E)) NRC identified Pronptly Violation is Opportunities OTHER CONSIDERATIONS (E) developed reflective of available to schedule for licensee 8s poor discover 1. Legal aspects and potential l Long term or declining violation such litigation risks l corrective performance (E) as through action (M) prior 2. Negligence, careless dis-notification regard, willfulness and 1 (E) management involvement Self- Degree of Prior Esse of earlier 3. Economic, personal or disclosing licensee performance and discovery (E) corporate Dain (M 25% if initiative (M) effectiveness there was LTo develop of previous 4. Any other regulatory frame-initiative to corrective corrective work factors that need to be identify root actions and action for considered: pending action cause) root cause) similar with regard to licensing, violations comission meeting, or press conference. Licensee Adequacy of the SALP - Period of time idertified as root cause consider: between 5. What is the Intended message a result of analysis for SALP 1 - (M) violation and for the licensee and the generic the violation SALP 2 - (0) notification ' industry? notification (M) SALP 3 - (E) received by (M) Licensee (E) - -- --- - NOTES---- --- - Copprehensive Prior Similarity corrective enforcement between the action to history violation and prevent including notification occurrence of escalated and (E) similar non-escalated violation (M) enforcement Imediate Level of corrective management action not review the taken to notification restore safety received (E) and conpliance (E) SAFETY SIGNIFICANCE: In determining the safety significance of a violation in conjunction with the enforcement process, the evaluation should consider the technical safety significance of the violation as well as the regulatory significance. Consideration should be given to the matter as a whole in light of the circunstances surrounding the violation. There may be cases in which the technical safety significance of the matter is low while the process control failure (s) may be significant, and, therefore, the severity level determination should be based more on the process control failure (s) than on the technical safety issue. The following factors should also be considered: 1) Did the violation actually or potentially inpact pubtle health and safety? 2) What was the root cause of the violation?
- 3) is the violation en isolated incident or is it indicative of a progranmatic breakdown? 4) Was management aware of or involved in the violation? 5) Did the violation involve willfulness?
^ >+
- Pmoosed Violation A-t
! 10 CFR 50, Appandix B, Criterion XI states, in part, that a test program shall be j established to ensure that all testing required-to demonstrate that components will perform satisfactorily in service and that the program shall include proof tests prior to
- installation and operational testing. The criterion further states that test procedures shall i include provisions to assuring that adequate test instrumentation is available and used.
i FPL Topical Quality . Assurance Report TQR 11.0, revision 4, " Test Control," states, in i part, that a test program shall be established to assure that testing required to demonstrate i that structures, systems and components will perform satisfactorily in service and that the pmgram shall include proof tests prior to installation, operational tests, and retest after repair. TQR 11.0 further states that test procedures shall incorporate requirements and acceptance limits in the applicable design and procurement documentation. Contrary to the above, on November 5,1994, and on November 6,1994, Power Operated Relief Valves V-1404 and V-1402, respectively, were installed in the Unit 1 Reactor Coolant System, placed into operation on November 22, and relied upon to be operable for appmximately nine months without adequate post-maintenance and surviellance testing sufficient to pmvide reasonable assurance that the valves would perfonn satisfactorily in service. As a result of these failures, Wh Unit 1 PORVs were
. inoperable from the time of their reinstallation after maintenance until August 11,1995, when the reactor coolant <ystem was depressurized and vented. Examples are:
- 1. No post-maintenance bench test was performed to ensure that the valves' main discs would change state in a pressurized envimament.
l
- 2. On November 25, 1994, and on Febmary 27, 1995, operational surveillance I testing, perfonned under Administrative Procedure 1-0010125A, revision 39, Data Sheet 24, did not employ adequate test instrumentation to detect the !
inoperability of both valves and did not employ test acceptance limits derived l from the the valves' design documentation. Specifically, the use of acoustic data, as opposed to system pressure reduction derived from valve capacity, to indicate valve position was insufficient to discem the difference between bypass flow through the PORV pilot valves and actual changes in main valve position. This is a Severity 1.evel II violatio: (supplement I). Proposed Violation B Technical Specification 3.4.13 requires, in part, that two Power Operated Relief Valves be operable in " Mode 4 when the temperature of any RCS cold leg is less than or equal to 304'F, Mode 5 and Mode 6 when the head is on the reactor vessel; and the RCS is not vented through a greater than 1.75 square inch vent." Contrary to the above, from November 22 through 27, 1994, and from February 27 through March 6,1995, St. Lucie Unit I was in conditions requiring operable Power
- l Opented Relief Valves but no operable releif valves in service. The inoperability of the 1
4 Power Opented Relief Valves resulted from a combination of personnel error during maintenance and inadequate post-maintenance and surveillance testing. This is a Severity Level II violation (Supplement I). l l 4 l l l 4 ) 1 i 4 1. e i e 4 4 J i s
_ . _ _ _ _ _ . _ _ _ _ _ . _ . - _ . _ _ _ _ _ . . ~ _ _ _ _ . _ . _ . _ . _ _ ._ _ - _ 4 i l St. Lucie Unit 1 PORY Inoperability i Ooerational Events On August 9, the licensee performed ASME Section XI stmke testing on V-1402 and V-1404 (Unit 1 PORVs) per AP 1-0010125A, revision 39, " Surveillance Data Sheets," Data Sheet 24. De test was performed with RCS pressure contmiled at 257 to 268 psig. The methodology of ] 3
- the test involved placing the PORV control switches in " override," (which ensured that the valves would not open) removing High Pressurizer Pressure bistables from the RPS cabinets l (which would send an "open" signal to the PORVs which would be blocked by the status of the control switches), and then, for each PORV, placing the control switch in " normal," which j would send the open signal to the PORV. The stroke time for each PORV was to be measured
. from the time the control switch was taken to " normal" to the time that acoustic monitors I j indicated that the subject valve had opened. Once a valve stroke time had been obtained, the j subject valve's control switch was to be returned to override to close the valve. I De results of the subject testing indicated that the valves did not stroke open. No acoustic
- signal was received in the control room. The licensee then returned the valves to service while j questions of acoustic monitoring calibration and threshold levels were considered. The test was reperformed approximately one hour later with temporary acoustic monitors and the resulting i acoustic signals indicated that both valves stroked in under one second. LTOP was placed back i in service, but Operations personnel began to question the validity of the test results, as no l changes were noted in either RCS or Quench Tank parameters. While evaluations were being )
l conducted, the unit was taken to Mode 4. At 7:03 p.m. on August 9, the valves were retested j and found to be inoperable based, in part, on observations of RCS and Quench Tank parameters. ! Each was declared out of service and the licensee entered TS 3.4.13 Action (c), which required . depressurization of the RCS and venting through a 1.75 square inch or greater opening within . 24 hours. . At 9:37 p.m., operators were directed by management to perform a cooldown of the RCS. ! When placing the SDC system in service, the SDC discharge relief valve lifted and would not reseat without securing the SDC pumps to reduce SDC system pressure at the relief valve. His
' issue will be discussed in a separate enforcement action; however, the inoperability of the SDC j system (due to the relief valve issue) precluded the licensee from cooling down and
! depressurizing Unit 1. Consequently, the licensee entered TS 3.0.3 at 10:45 a.m. on August
- 10 and began a heatup to greater than 304'F, a plant condition for which TS 3.4.13 did not l apply. 305'F was achieved at 11
- 53 a.m.
1 The SDC system was returned to service on August 11. A cooldown was commenced at 6:25 l
- a.m. the same day. The licensee made plans to re-enter TS 3.4.13 AS (c) during the cooldown, j and to create the required vent path by removing the bonnet of PCV-1100F, one of two i pressurizer spray valves, which would create the required vent path to RCS cold leg IBl. The
- subject AS was entered at 7
- 15 a.m. on August 11 and exited at 8:40 p.m. the same day, when
- the system was vented.
i , PORV Operation l 1
1 J: r . j- The PORV design in question is a Dresser Industries Model 31533VX-30. The valve is a 2.5" i inlet by 4" outlet pilot operated valve with a relief capacity of 153,000 lbm/hr. The internals of the valves are displayed in Figure 1. ) The valve, as installed in Unit 1, is actuated by a solenoid valve, which acts on the pilot valve j operating lever to open the pilot valve. The open pilot valve creates a vent path from below the j main disc of the main valve, thmugh holes machined in the main disc guide, to the quench tank.
- The nduction in pressure below the main valve main disc allows the disc to move open (down, j in Figure 1) under the force of system pressure acting on the main disc.
i 4 When pressure has been reduced below the applicable rescat pressure (depending upon PORV a mode - normal, LTOP low range, or LTOP high range), the solenoid valve is deenergized, I which closes the pilot valve and isolates the vent path fmm below the main valve disc to the
- quench tank. Once the vent path is isolated, pressure builds up below the main valve disc as
- system pressure is admitted to the space through an orifice in the main valve retainer plug.
j When pressure has been built up below the main valve disc in this manner, the disc is moved 4 into a closed position under pressure aided by spring force. I Dimynostic Maintenance
~ The subject PORVs were removed on August 12 and placed on a test bench for lift tests to be j conducted under air pressure. Both valves were tested at a number of pressures within the i
LTOP range and were found to be inoperable. Disassembly and inspection revealed that the main disc guide was installed upside down, with the holes (required to vent the space below the
- main disc) located at the upper extreme of the main disc cavity such that pmper venting below
- the main valve disc could not take place.
i As a function of diagnosing the mot cause, the licensee reversed the main disc guide orientations
- (to the proper orientation) and retested the valves under air pressure. Both valves tested satisfactorily. The licensee also sent a spare valve to Wylie Laboroatories for testing under
- water and steam pressure, as these conditions could not be established at the site. The spare PORV was tested under water and steam with the main disc guide misoriented (the as-found
, condition of the Unit 1 PORVs) at pressures ranging fmm LTOP pressures to NOP ranges. The PORV failed to open under any condition with the rnain disc guise misoriented. Additionally,
- it was found that
e Under water pressure at 335 ar.d 450 psig,10-15 psig was developed at the discharge of the pilot valve, indicating that some leakage around the main disc
, guide was possible, but not enough to provide venting sufficient to open the PORV.
o Under steam pressure from 50 psig to 450 psig in 50 psig increments, 20-60 psig
- was developed at the pilot valve discharge, e Under steam pressure at 2400 psig,1500-1800 psig was developed at the pilot valve discharge.
(. ; t I The pressures and media flow detected at the pilot valve discharge indicated that acoustic data may be received during PORV testing without being indicative of a PORV changing state. Maintenuce , The subject PORVs were last reworked in November,1994, as part of the Unit I refueling outage. The rework was conducted by employees of Furmanite, which were used by the licensee for outage-related valve work. The PORVs were each worked by the same two workers. 'Ihe work package which directed the rebuild invoked the licensee's procedure 1-M-0037, tevision 6, " Power Operated Valve Relief Valve Maintenance." The licensee determined that step 9.8 " reassembly of Main Valve," step 7, which directs the installation of the main disc guide, did not include a QC hold point to verify proper installation. It was noted that this is the only component which can be installed improperly and result in undetected ~inoperability. The procedure was revised to include a QC Hold Point prior to the valves' reassembly. i The inspector questioned the licensee as to post-maintenance testing requirements as applied to the PORVs. The licensee stated that post-maintenance testing was limited to a bubble test for seat leakage prior to reinstallation. The inspector noted that 1-M-0037 only required the noted , bubble test as post-maintenance testing and, in fact, contained a note explaining that lift set point testing was not required, as the valve was lifted based upon solenoid valve input. The procedure did not mquire a proof that the valve would change state under presseure prior to installation, but did include a check for main disc mechanical freedom. In discussing post-maintenance testing with the licensee, it was stated that, while no documented : lift test existed, air lifts were typically performed as a function of preparing for seat leakage tests. It was explained that, upon initial reassembly, the PORVs rarely, if ever, satisfied seat leakage criteria due to relative misalignment between the main valve disc and its seat. As a result, the licensee stated that lifts under air pressure were performed as a matter of course to allow the main disc to orient itself properly against its seat. The inspector noted that the goveming procedure included a note to this affect, but no evidence existed to indicate that lifts had occurred on the test bench. The licensee stated that, in discussions with the Furmanite Supervisor who oversaw the ~ rebuilding of the PORVs during the.1994 outage, the Supervisor stated that he recalled at least 6 lifts under air pressure per PORV in attempts to obtain satisfactory seat leakage tests. No documentation existed to validate the claim. The licensee stated that, when testing of the spare PORV at Wylie was complete, and the PORV was retumed to the site, Furmanite was going to be allowed to rebuild the valve and demonstrate that lifts could be achieved with the main disc guide installed backwards. The inspector discussed the plausibility of such lifts with the valve vendor representative on site, who stated that, in principle, such lifts were possible it sufficient gaps existed between the main disc guide and the gasket below the guide. The results of the test are pending. The inspector concluded that post-maintenance testing, described in 1-M-0037, was inadequate to verify that maintenance had been satisfactorily performed on the PORVs. As described below, surveillance testing was performed on the PORVs during unit heatup and repressurization
! l . . i l following the Unit 1 outage. However, the inspector concluded that insufficient testing had been performed on the PORVs, prior to installation, to obtain a masonable assurance that the PORVs l would perform satisfactorily in the LTOP conditions which would exist prior to the subject
- surveillance test.
De inspector discussed the issue of post-maintenance testing with Operations personnel. It was ; i confirmed that Operations had accepted the subject PORVs from maintenance with the 1 assumption that they had been pmperly tested and, as such, considered them operable upon installation. The inspector found this assumption to be counter to the understanding of Maintenance personnel, as in-situ surveillance testing was considemd to be the post-maintenance test of the valve overhaul. The inspector reviewed PWOs 63/8104 and 63/8105, which dimeted I&C to perform PORV solenoid valve inspection and testing on V-1402 and V-1404, ! respectively. Included in the task description of each PWO was a requirement to " Notify Ops I Dept to perform valve stroke time verification test per QI 11-4/AP 1-0010125A DS-10." The l mferenced procedum and data sheet were the same as that described below for PORV stmke time testing. The inspector concluded that the Maintenance and Operations Departments were Ner completely different impressions of the status of the valves. Surveillance Testing The inspector questioned the licensee as to whether any in-situ testing had been performed on I the PORVs since their installation during the 1994 outage. The licensee stated that two tests had been perfonned; one on November 25, 1994, with RCS pressure at 245 psia, and one on February 27, 1995, with RCS pressure at 1750 psia. Both tests were documented as satisfactory. The satisfactory results were, by pmcedure, based upon acoustic data, as opposed to system parameter changes (e.g. RCS pressure, quench tank conditions). As stated above, results fmm testing at Wylie indicated that sufficient flow could be developed through bypass around a misinstalled main disc guide (and then out an open pilot valve) to pmvide acoustic data without actual main valve movement. l The inspector concluded that the acceptance criteria provided for verifying PORV operability , in OP l-0010125A was insufficient to demonstrate valve operability in that tests performed on { November 25, 1994, and Febmary 27, 1995, did not detect the inoperability of the subject l PORVs. i PORV Operability The inspector reviewed the licensee's activities with regard to root cause determination for the subject PORV conditions. In particular, the inspector noted the following: ; e Bench testing of both PORVs, once removed from the system and prior to individual valve disassembly, indicated that the valves would not lift under air pressure at any process pressure from the LTOP range to the NOP range. e Disassembly of each PORV resulted in the discovery ofincorrectly installed main valve disc guides.
. . .~ . _ _ _ _ _ _ . _ _ _ _ .. _ __ .. __. ._ _ _ _.
.4
-* Upon conection of main valve disc guide orientation alone (i.e. no other piece i part changes or replacement) for each PORV, bench testing under air pressure L resulted in satisfactory lifts.
e Wylic Laboratory testing of a spare PORV, under water and steam, under ! pressure conditions ranging from below LTOP setpoints to above NOP, indicated that'no lift was possible with the main valve disc guide installed backwards, i As a result, the inspector concluded that the PORVs were inoperable from the time they were j installed in the RCS during the 1994 refeeling outage until they were removed and reworked in l August,1995.- i ! Imnet on Unit 2 1 Unit 2 is not susceptible to the same failure, as Unit 2 employs Garrett / Crosby _ PORVs, which are of distinctly different design. Additionally, the Unit 2 PORVs provide direct main valve position indication, provided by a indexing rod attached to the main valve disc which activates a reed switch. The inspector reviewed AP 2-0010125A, revision 43, " Surveillance Data Sheets," Data Sheet 24, which directed surveillance testing for Unit 2 PORVs. The inspector found that the procedure directed that stroke time be based upon indicated valve position change, as opposed to acoustic data. [ FIND OUT IF UNIT 2 PROCEDURE HAS BEEN REVVED TOO) Imnact on Unit 1 The St. Lucie Unit I design employs two PORVs, which provide overpressure protection both during normal operation and for LTOP concerns. - Additionally, the PORVs are employed in EOPs for once through cooling in the event of a loss of other core heat removal options. During power operations, PORVs are designed to open only in the event of a high pressure reactor trip, and are sized to allow the unit to suffer a loss of load trip from full power without lifting a pressurizer code safety valve. Accident analyses do not credit PORV operation. During low-mode conditions, the PORVs operate on one of two selectable LTOP setpoints, depending upon cold leg temperature and whether a heatup or cooldown is in progress. Following the Unit I refueling, the unit was filled solid on November 22. The RCS was pressurized and in a condition requiring LTOP from November 22 through November 27. The unit was subsequently at NOP until a Short Notice Outage (SNO) in February,1995. During the SNO, the unit was in conditions requiring LTOP protection from February 27 through March 1
- 6. Notably, on March 4,1994, Unit 1 experienced a loss of shutdown cooling event with the j unit in a solid water condition. The condition was corrected by operators, but not before RCS l pressure had exceeded the LTOP anticipatory alarm setpoint. No LTOP lift of PORVs was demanded or experienced (peak pressure was 343 psia, LTOP setpoint at the time was 350 psia). !
On July 11,1994, Unit I suffered a high pressure trip (see IR 95-14) which, according to the licensee at the time of the trip, included a lifting of both PORVs. The conclusion was supported at the time by the inherent design of the system, the fact that acoustic data indicated that the i l
i, i PORVs lifted, and noted increases in Quench Tank temperature. The licensee is now doubtful that the PORVs lifted during the trip, based upon a review of data (which suggested that
- pressure drifted above the PORV setpoint, as opposed to plateauing) and of analyses which j showed that the post-trip loss of heat source acts, in conjunction with steam reliefs to limit
- pressure increases.
l
- As regards once through cooling functions of the PORVs, the St. Lucie IPE includes PORV use
- in early post-accident heat removal for reactor trips, loss of pressure control events, loss of offsite power events, main steam line break accidents, and steam genemtor tube ruptures.
The licensee performed a PRA analysis which quantified the change in CDF for common-mode failures in PORVs. The licensee detennined that the Unit 1 CDF had increased by an approximate factor of 3 for the period of inoperability of the subject PORVs. With regard to LTOP concerns, the licensee analyzed the impact of a loss of LTOP PORV function for the energy and mass addition events in the original LTOP design basis. The licensee determined that, based upon current levels of Unit I fluence, the maiximum allov/able vessel stress would not be exceeded for any of the previously-analyzed LTOP events. Pressure relief by pressurizer code safety valves, or shutdown cooling relief valves (depending upon the event considered), were found to be sufficient to limit peak pressures to below maximum allowable values. l l
a 4 __.a _.Aa- ,E .. A..A-, - m 4 A -._- N d 4 Figure 1 I 1
6 i BRIEFING ON USE OF DISCRETION TO PROPOSE CIVIL PENALTY ! FOR INOPERABLE PORVs AT ST. LUCIE t Both PORVs were inoperable from the time they were installed in the RCS on November 5,1994, during the 1994 refueling outage until they were removed and reworked in August 1995. MISSED OPPORTUNITIES
- 1. Maintenance on the PORVs did not include orecautions to ensure onerability and protect aoainst a common mode failure.
The PORVs were last reworked in November 1994 in the Unit I refueling outage. The rework was conducted by Furmanite. Post-event disassembly and inspection revealed that the main disc guide had been installed upside down, with the holes (required to vent the space below the main disc) located at the upper extreme of the main disc cavity such that proper venting below the main valve disc could not take~ place. Maintenance was performed by the same two workers. The maintenance procedure did not include a QC hold point to verify proper installation. No independent verification method was used to ensure the valve was properly assembled. The main disc guide was the only component which could be installed improperly and result in undetected inoperability. FP&L could have used several standard methods to ensure that a common mode error did not cause both PORVs to be inoperable, i.e., use of different work crews on each valve, independent verification of the maintenance work steps, or a QC holdpoint.
- 2. Post Maintenance Testina was limited to a seat leakaae test and the scoce/ responsibility for testina was not understood betweer Operations and Maintenance Post-maintenance testing was limited to a bubble test for seat leakage prior to reinstallation. Procedures specifically excluded lift test requirements with an explanation that the valve was lifted based upon solenoid valve input. The procedure did not require a verification that' the valve would change state under pressure prior to installation.
Operations accepted the PORVs from Maintenance with the assumption that they had been properly tested and, as such, considered them operable upon installation. Maintenance personnel thought in-situ surveillance testing was to be used as the post-maintenance test. Maintenance and Operations were under completely different impressions of the status of the PORVs following installation in the system. As a result of this misunderstanding, the PORVs were placed in the RCS and declared operable without reasonable assurance that the PORVs would perform satisfactorily in the LTOP conditions which would exist prior to performance of the surveillance test.
- 3. Inservice surveillance testina did not demonstrate that. after complete valve disassembly and reassembly. that the valve would chanae state under pressure.
There are no specific technical specification surveillance requirements. Surveillance tests are performed to comply with the ASME Code. The testing involves valve stroke testing associated with its use in LTOP. Surveillance tests performed on November 25, 1994 and February 27, 1995, used acoustic data, as opposed to system pressure changes, to indicate valve position. FP&L failed to recognize that the PORV pilot valves
allow;d sufficient bypass flow to actuate the acoustic monitors. An indication of only one lit acoustic monitor LED was sufficient to pass ( the test. Only the acoustic monitor annunciator was used when other control room indications could have been used to confirm valve operation. On August 4, 1995, FP&L performed a surveillance test and did not receive an acoustic signal in the control room, but an increase in - tailpipe temperature was observed, and an increase in acoustic levels was recorded on a plant computer. RCS and Quench Tank parameters in the control room exhibited less than expected changes. The FP&L assumed the acoustic monitor was inoperable. FP&L then contacted the vendor to discuss possible reasons for the observed valve performance. While evaluations were being conducted, the unit was taken through LTOP conditions to Mode 4. At 7:03 p.m. on August 9, 1995, the valves were retested and found to be inoperable based, in part, on observations of RCS and Quench Tank parameters.
- 4. The indications of valve operability after a unit trio were missed.
^ On July 11, 1995, Unit 1 experienced a high pressure trip (see IR 95-14). According to FP&L, at the time of the trip, both PORVs lifted. The conclusion was supported at the time by the inherent design of the system, the fact that acoustic data indicated that the PORVs lifted, and noted increases in Quench Tank temperature. Upon a re-review of data (which suggested that pressure drifted ab'ove the PORV setpoint, as opposed to plateauing) and an analysis which showed that the post-trip loss of heat source acts, in conjunction 'with steam reliefs, to limit pressure increases, FP&L concluded that the PORVs probably did not lift following the. trip. CONCLUSION Section Vll. A of the Enforcement Policy allows the exercise of discretion to propose a civil penalty when the case involves poor performance. The performance in this case was particularly poor throughout the control of the maintenance and testing of these valves and led to a common mode failure of the PORVs. Expected provisions to ensure valve operability were not implemented. A critical point in the reassembly did not have a QC holdpoint; other independent verification methods were not employed. Engineering analysis and plant safety committee reviews of the acceptability of post maintenance testing and inservice testing contained basic flaws in ensuring methods were employed to assure operability. These flaws included accepting post-maintenance testing that only verified seat leakage prior to putting the valves back in service; miscommunication between Operations and Maintenance on scope of post-maintenance testing; and failure to provide an adequate inservice test to ensure PORV operability. Operator attention to diverse control board indications during testing was lacking and only when the one parameter that was required, i.e., the acoustic monitoring indication, failed, did operators question the other indications they were getting. The post trip data analysis during the July 1995 unit trip was not indepth. Therefore, we propose that a base civil penalty be imposed in this case to ensure the appropriate regulatory message that programs must provide defense in depth to preclude common mode failures. The design and operation of the PORVs are discussed in Attachment 1.
l Attachment 1 ! DESIGN AND OPERATION OF THE PORVs . l St. Lucie Unit 1 employ two PORVs. Purposes: (1) Pressure relief coincident with a high pressure reactor trip - open at 2400 psia. Accident analyses do I not credit the valves' actuation; (2) Pressure relief under LTOP conditions - open at two selectable LTOP setpoints based upon RCS temperature; (3) Once j through cooling - credited in the E0Ps for providing core cooling in the event ' of a loss of heat sink. The Unit 1 PORVs are Dresser Industries Model 31533VX-30 pilot operated relief l valves. The main valve (responsible for actual RCS pressure relief) opens by the force of water or steam acting on the main valve disc / seat interface. The ; main disc moves within a guide cylinder and its movement is governed both by ! the differential pressure established across the disc and spring force which attempts to move the disc into a closed position. A differential pressure is established across the main disc when the valve's pilot valve opens, venting a space inside the main disc to a low pressure area (the tailpipe). The pilot valve is actuated by a solenoid acting on the pilot valve lever. 1 When actuation is required, a signal is sent to the actuating solenoid, which strokes the pilot valve lever to open the pilot valve. A vent path is thus established from the inside of the main disc, through the pilot valve, to a low pressure area. The resulting differential pressure across the valve main disc opens the PORV main valve. ; i Indications of valve operation include acoustic flow monitors at the discharge of each PORV, tailpipe temperature indication, and indication of solenoid energization. PORV operation can also be inferred from changes in quench tank l parameters (temperature, pressure, and level) or changes in RCS pressure. ; Output of the acoustic monitors is indicated in the control room, behind the main control panels. The discretized output is indicated by ten LEDs per instrument channel. On the energization of a single LED, a control room annunciator is energized, alerting operators. t
Attachment 2
')
ASME STR0KE TESTING METHOD ASME Section XI stroke testing involved:
- 1) placing the PORV control switches in " override" (which ensured that the valves would not open),
- 2) removing High Pressurizer Pressure bistables from the RPS cabinets (which would have sent an "open" signal to the PORVs which would be blocked by the status of the control switches), and
- 3) for each PORV, placing the control switch in " normal," which would have sent the open signal to the PORV.
The stroke time for each PORV was measured from the time the control switch was taken to " normal" to the time that acoustic monitors indicated that the subject valve had opened. Once a valve stroke time had been obtained, the subject valve's control switch was returned to override to close the valve. l
Attachment 2
- Reauirement-for ASME Code Testina
! The.PORVs.are classified by FP&L as safety-related and are ASME Code Class 1, RCS pressure boundary valves. .The requirement for ASME Code testing is tied j! down by Technical Specification 4.0.5 which requires, in part, that inservice E ~ inspection of Code Class 1 valves shall be performed in accordance with
- . 'Section XI of the ASME Boiler and Pressure Vessel Code and applicable' Addenda
- as required by 10 CFR 50, Section 50.55a(g).
The edition and addenda of the ASME Code to which St. Lucie is coamitted is
-tied down through Florida Power and Light's Second Ten-year Inservice
- Inspection Interval Inservice Testing Program For Pumps and Valves, Document Number JNS-PSI 203, Revision 5, states, in part, that, between February 11, 1988 and February 10, 1998, the St. Lucie Unit 1 ASME Inservice Inspection (IST) Program will meet the requirements of the ASME Boiler and Pressure Vessel Code (the Code), Section XI, 1983 Edition.
Section XI of the 1983 ASME Boiler And Pressure Vessel Code, article IWV-3000, Test Requirements, Section IWV-3200, Valve Replacement, Repair, and Maintenance, requires, in part, that when a valve or its control system has been replaced or repaired or has un6rgone maintenance that could affect its performance, and prior to the time it is returned to service, it shall be tested to demonstrate that the performance parameters, which could be affected by the replacement, repair, or maintenance are within acceptable limits.
_ _ ___ . . . . _ _ _ . _ _ _ . _ ~ _- _ . _ - _ _ _ _ . . . _ . _ . _ I
**coconocococcoooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooooo
- User name: KDL Queue: HPIIID-AT1-3033
- File name:
f* ENFDIS2.STL ^ Server: AT2
- o Directory: *
Description:
- October 30, 95 12:24am
- oco********************************* ******************************************
- K K DDDD L *
- K K D DL
- t
- K K' D DL *
- KK D DL *
- KK D DL *
- K K D DL *
*- K K DDDD LLLLL
- occo********************************************************w*******************
- W W ooo rrrr dddd PPPP eeeee rrrr fffff eeeee ccc ttttt *
- W Wo or rd dP Pe r rf e c c t *
- W Wo or rd dP Pe r rf e c t *
- WWWo o rrrr d d PPPP eeee rrrr ffff eeee c t *
- WWWo orr d dP e rr f e c t *
- WW WW o or r d dP e r r f e c c t *
- W W ooo r r dddd P eeeee r rf eeeee ccc t
- A.
CnAt Wa8, W ' pyc -
. zM [ ff-Z36 ,
l ENFORCEMENT ACTION WORKSHEET cloSfp I INADEQUATE CONFIGURATION MANAGEMENT l l PREPARED BY: Mark S. Miller DATE: July 1, 1996 )
~
NOTE: The Section Chief of the responsible Division is respons le-for prepaTaT5n of this EAW and its distribution to attendees prior to an Enforcement Panel. The Section Chief shall also be responsible for providing the meeting location and telephone bridge numbur to attendecs via e-mail [ENF.GRP, CFE, OEMAIL, JXL, JRG, SHL, LFD; appropriate Ril DRP, DRS; a ppropriate NRR, NMCS). A Notice of l Violation (without "boilerplate") which includes the recomriended severity level for the violation is required. Copies of applicable Technical Specifications tv license conditions cited in the Notice or other
- I reference material needed to evaluate the proposed entorcement action are required to be enclosed.
This Notice has been reviewed by the Branch Chief or Divis n Director and each violation includes the appropriate leveljf specifi y as to how and when the requirement was violated. Facility: Unit (s): Docket Nos: License Nos: Inspection Report No: 9 6--o@ Inspection Dates: l Lead Inspector:
- 1. Brief Summary of Inspection Findings: [Always include a short statement of the ,
regulatory concern / violation. Reference and attach draft NOV. Then, either summarize the inspection findings in this section or reference and attach sections of the inspection report. Inspectors are encouraged to utilize the Noncompliance information Checklist provided in Enclosure 4 to ensure that the information gathered to support the violation is complete.] A number of unrelated findings over three inspection periods has indicated that the licensee has inadequately managed configuration control, particularly in the area of ensuring that design changes are reflected in procedures. A number of annunciator response summary procedures have been found to include erroneous information, and several have been traced back to the hardware changes which rendered the procedures inaccurate. While none of the individual occurances (with respect to annunciators) presented high safety significance, the findings have illustrated an ongoing failure' to properly factor design changes into procedures due, primarily, to a failure to identify, up front, the procedures which would be affected and to properly track the procedure revisions to closure. In addition to the annunciator issues, one drawing was identified as having been overlooked in the design change process, and one procedural qt deficiency, identified by the licensee is identified. The licensee- ) PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
e t ENFORCEDENT ACTION , woaxsumar F identified issue involved a failure to include prerequisites in a
- procedure which would have been required to ensure the validity of the licensee's full core offload spent fuel pool heat load calculations.
Core offload began before the failure was identified, and 7 assemblies were offloaded before operations were secured and corrective actions
- taken.
See attached IR feeder and proposed NOV for details. a i I 1 l i l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
O
- ENFORCEMENT ACTION g WoRKSHEET
- 2. Analysis of Root Cause:
Lack of formality in the licensee's program for preparing and implementing Plant Change /Hodifications (PC/Ms), which did not explicitly require that affected procedures be identified and reviewed / changed during the development and execution of PC/Ms.
- 3. Basis for Severity Level (Safety Significance): [ Include example from the supplements, aggregation, repetitiveness, willfulness, etc.]
Aggregation of examples and application of Supplement I, C.7, a breakdown in the control of licensed activities involving a number of violations that are related that collectively represent a potentially significant lack of attention toward licensed activities. While safety significance with respect to annunciator response procedure issues is difficult to assess, the number of examples identified (both in the citation and in addition to the citation) by NRC indicate that a weakness in incorporating design changes into procedures has existed for l some time. Additionally, the licensee-identified portion of the violation (involving a failure to include calculational assumptions as prerequisites in operational procedures) represented a challenge to the Spent Fuel Pool's ability to remove the decay heat associated with a full core offload.
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
[by EA#, Supplement, and Identification date.] EA 96-040 - Boron Overdilution Event, Supplement 1, 1/22/96 EA 95-180 - Inoperable PORVs due to Inadequate PMT, Supplement 1, 8/4/95
- 5. Identification Credit? No The configuration management issue was raised by NRC initially in March, 1996, as walkdowns of annunciators indicated that inaccuracies were frequent in annunciator response procedures. The issue grew through 5/96, with additional examples identified and the sources of some of the inaccuracies (PC/M implementation) being identified by NRC. Licensee corrective action began in late April, when we identified drawing errors ,
and additional annunciator response procedure errors. Enter date Licensee was aware of issues requiring corrective action: 1 [4/96]
- 6. Corrective Action Credit? Yes Brief summary of corrective actions:
In response to the issue, the licensee adopted corrective actions which included: e Implementing design control processes from Turkey Point, which ai PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
O ENFORCEMENT' ACTION WORKSHEET c provided more positive control over the initial reviews and documentation of required actions for PC/Ns. e Performing reviews of all Unit I outage related PC/Ms to ensure that required procedural changes were identified.
- Requiring that all PC/M paperwork for modifications installed i during the current Unit I outage be closed out prior to returning the affected system to serv;c.e.
- Revalidating open items from previous PC/Ms on both units and establishing timelines for closure of the open items.
Initiating a vertical slice inspection of selected, PRA-significant (EDGs, HPSI, and CCW), systems to ensure that the systems were properly installed and that procedures were adequate. Explain application of corrective action credit: Corrective action appears to be of appropriate scope.
- 7. Candidate For Discretion? Yes Explain basis for discretion consideration:
Licensee's performance has been considered superior in the past.
- 8. Is /. Predecisional Enforcement Conference Necessary? No
- 9. Non-Routine Issues / Additional Information:
l l 4 L d PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
ENFORCEMENT ACTIoM , woRKsussT ! 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: [EICS to provide] [lf inconsistent, include:) L Basis for Inconsistency With Previously Issued Actions (Guidance) i
- 11. Regulatory Message:
Positive control must be established and maintained over the design change process, with particular emphasis on ensuring that design features and constraints are properly-incorporated into procedures and drawings.
- 12. Recommended Enforcement Action:
SL IV
- 13. This case Meets the Criteria for a Delegated Case. [EICS - Enter Yes or No]
- 14. Should This Action Be Sent to OE For Full Review 7 [EICS - Enter Yes or No)
If yes why:
- 15. Regional Counsel Review [EICS to obtain]
No Legal Objection Dated:
- 16. Exempt from Timeliness: lEICS)
. Basis for Exemption:
. Enforcement Coordinator:
DATE: PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE e , - -w.. + -- - ,-n,
ENFORCENENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION [] Problems categorized at Severity Level ~I or II. [] Case involves overexposure or release of radiological material in excess of NRC requirements. l [] ' ' Case involves particularly poor licensee performance. [] Case (may) involve willfulness. Information should be included to address whether or not the region has had discussions with 01 regarding the case, whether or not the matter has been formally referred to 01, and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, wi11 fulness, and/or management involvement should also be included. [] Current violation is directly repetitive of an earlier violation. [] Excessive duration of a problem resulted in a substantial increase in risk. [] Licensee made a conscious decision to be in noncompliance in' order to obtain an economic benefit. l
- [] Cases involves the loss of a source. (Note whether the licensee self- )
identified and reported the loss to the NRC.) [] Licensee's sustained performance has been particularly good. [] Discretion should be exercised by escalating or mitigating to ensure that the proposed civil penalty reflects the NRC's concern regarding the viola'isn at issue and that it conveys the appropriate message to the licensee. Explain. e' 8 I PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
i
, Enclosure 3 i
REFERENCE DOCUMENT CHECKLIST , 4 [X] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: 96-08 [] Licensee reports: , [] Applicable Tech Specs along with bases: j [] Applicable license conditions . 4 [] Applicable licensee procedures or extracts [] Copy of discrepant licensee documentation referred to in citations such 4 as NCR, inspection record, or to t results [] Extracts of pertinent FSAR or Updated FSAR sections for citations i involving 10 CFR 50.59 or systems operability 4 [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections j [] Other miscellaneous documents (List): s 4 E n 7 4 i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
Inspection Report 96-04 hientified several potential configuration ; control weaknesses involving inaccuracies in control room annunciator ' response summaries and engineering drawings. Of the deficiencies noted, l one was tied to an inadequacy in the implementation of a PC/M. Unresolved Item 96-04-05, " Configuration Control Management," was opened to track the issue while the inspection scope was expanded. Inspection , Report 96-06 documented additional deficiencies, identified during system walkdowns, which were the result of PC/M implementation , inadequacies. During the current inspection period, additional PC/M l implementation issues were identified. The individual issues are as follows- : l e IR 96-04 documented the fact that, on January 6, 1995, the i 4 licensee closed out PC/M 109-294 [Setpoint change to the Hydrazine l Low Level Alarm (LIS-07-9)] without assuring that affected I
- procedure ONOP 2-0030131, " Plant Annunciator Summary", was l revised. This resulted in annunciator S-10 HYDRAZINE TK LEVEL LO l
- i. showing an incorrect setpoint of 35.5 inches. !
e IR 96-06 documented the fact that, on May 16, 1994, the licensee , closed out PC/M 341-192 [ICW Lube Water Piping Removal and CW Lube i Water Piping Renovation). The as-built Dwg. No. JPN-341-192-008 was not incorporated in Dwg. No. 8770-G-082, " Flow Diagram l Circulating and Intake Cooling Water System", Rev 11, sheet 2 ) issued May 9, 1995 for PC/M 341-192. This resulted in Dwg. No ; B770-G-082 erroneously showing valves I-FCV-21-3A & 3B and ! associated piping still installed. e IR 96-06' documented the fact that, on February 14, 1994, the licensee closed out PC/M 268-292 [ICW Lube Water Piping Removal and CW Lube Water Piping Renovation] without assuring that affected procedure ONOP 2-0030131, " Plant Annunciator Summary", was revised. This resulted in annunciator E-16 CIRC WTR PP LUBE WTR SPLY BACKUP IN SERVICE incorrectly requiring operators verify the position of valves MV-21-4A & 4B following a SIAS signal using control room indication. These valves no longer received a SIAS signal, were deenergized and had no control room position indication. e This inspection report documents the fact that, on October 28, 1992, the licensee closed out PC/M 275-290 [FIS-14-6 Low Flow Alarm and " Manual" Annunciator Deletions] without assuring that affected procedure ONOP 2-0030131, " Plant Annunciator Summary", was revised. This resulted in safety-related annunciators LA-12 ATM STM DUMP MV-08-18A/18B OVERLOAD /SS ISOL and LB-12 ATM STM DUMP MV-08-19A/19B OVERLOAD /SS ISOL incorrectly requiring operators to check the Auto / Manual switch or switches at RTGB-202 and PACB for the MANUAL position. The relay contacts which energized these annunciators based on switch position were removed to eliminate nuisance alarms.
- During the current inspection period, the licensee identified the fact that assumptions made in the heat load calculation supporting the Unit 1 full core offload were not appropriately factored into PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
the applicable procedure. Specifically, PC/M 054-196, supplement 0, St. Lucie Unit 1 Cycle 14 Reload," included, in Attachment 8, } operational limitations which resulted from the heat load
- calculation performed to support the full core offload. These
. ' included: 1 1 l e Ensuring that initial SFP temperature was less than or equal l J to 106"F. i e Ensuring that the reactor was subcritic' al for at least 168 ! hours prior to commencing the offload.
- e -Verifying that the SFP high temperature alarm, which j annunciated in the control room, was operable.
j e Verifying that two SFP cooling pumps were in operation. 1- e Verifying that CCW flow to the fuel pool heat exchangers was maintained at approximately 3560 gpm when two SFP cooling jl pumps were operatisc. ! On May _12, the licensee's QA organization identified these deficiencies after the offload of 7 fuel assemblies. The ! defueling evolution was subsequently. stopped, and the i prerequisites were added to OP 1-1600023, " Refueling Sequencing Guidelines," as revision 62 to the procedure. l I Only four examples of inaccurate annunciator response summaries are
- cited above; those being inaccuracies for which the inspectors- 1 4 determined which PC/M resulted in the inaccuracies. . IR 96-06 summarized recent NRC findings in this area, and stated that ten examples of ' alarm :
i setpoint inaccuracies and 18 other (e.g. wrong sensing element, wrong - action directed) inaccuracies in the Annunciator Response Summaries had , j been identified in both units' ICW and CS systems. l l 10'CFR 50 Appendix B, Criterion III, " Design Control," requires, in 4 part, that measures be established to ensure that applicable regulatory requirements and the design basis are correctly translated into ! specifications, drawings, procedures, and instructions. -The licensee's j Topical Quality As:urance Report, TQR 3.0, revision 11, " Design 4 Control," included the following provisions: l
- e Section 3.2.2, " Design Change Control," stated, in part, " Design i
changes shall be. reviewed to ensure that implementation of the design change is coordinated with any necessary changes to operating procedures..." e Section 3.2.4, " Design Verification,". stated, in part, that
" Design control measures shall be established to independently verify that design inputs, design process, and that the design inputs are correctly incorporated into design output."
The inspectors concluded that the. examples cited above failed to satisfy these criteria and, therefore, constituted a violation (VIO 96-08-XX,
" Failure to Adequately Manage Configuration Control"). In the cases of PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
procedural inadequacies brought on oy the igplementation of PC/Ms c the 1 inspectors concluded that a lack of detailed preimplementation reviews ensted with respect to the impact of a given PC/M on procedures. While preptring PC/Ms, the licensee included a review for impact to other organizations' procedures and documented potential impacts on PC/M rwirw forms; however, this documentation amounted to a "yes" or "no" determination, as opposed to specifying the procedures which required revision. As a result, no formal process tracked the completion of 4 'crmally specified actions. j The licensee's QA organization performed an audit of this area and documented their findings in QSL-PCM-96-11, "PC/M Design Control." The
- licensee found the following with regard to the process
- Plant procedures and instructions did not adequately define the review and comment process by plant departments impacted by PC/Ms
- or the resolution to those comments.
.
- Plant procedures and instructions did not adequately address the identification of plant procedures impacted by PC/Ms.
e Plant procedures and instructions did not adequately address the , review of Safety Evaluations for impact on plant procedures and l 4 instructions (this applied to Safety Evaluations which included conditions to ensure that the assumptions in the evaluations were ; maintained valid). The inspectors found the licensee's findings to be in general agreement with observations made by the NRC. In response to the issue, the licensee adopted corrective actions which included: e Implementing design control processes from Turkey Point, which provided more positive control over the initial reviews and documentation of required actions for PC/Ms. e Performing reviews of all Unit 1 outage related PC/Ms to ensure that required procedural changes were identified. e Requiring that all PC/M paperwork for modifications installed during the current Unit 1 outage be closed out prior to returning the affected system to service. e Revalidating open items from previous PC/Ms on both units and establishing timelines for closure of the open items. e Initiating a vertical slice inspection.of selected, PRA-significant (EDGs, HPSI, and CCW), systems to ensure that the systems were. properly installed and that procedures were adequate. The inspector concluded that the licensee had moved aggressively to address the PC/M issues discussed above and to ensure that the as-built configuration of the plant was adequate. The overall adequacy of the licensee's actions will be determined in followup inspections to the PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
j ., j violation described above. i' t l 4 f i 4 i a e 3 i i i i 4-l t l 1 PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
o l 10 CFR.50 Appendix B, Quality' Assurance Criteria for Nuclear Power . . Plants and Fuel Reprocessing Plants," Criterion III required, in part, , that measures be established to assure that applicable regulatory . - requirements and the design basis for those structures, systems, and components to which this' appendix applies are correctly translated into , specifications, drawings, procedures, and instructions. FPL Topical ' Quality. Assurance Report, TQR 3.0, revision .11, " Design Control," , Section 3.2.2, " Design Change Control," stated, in part, " Design changes . shall be reviewed to ensure that implementation of the design change is ! coordinated with any necessary changes to operating procedures..." i Section 3.2.4, " Design Verification," stated, in part, that " Design control measures shall be established to independently verify the design inputs, design process, and that-the design inputs are correctly incorporated into design output." < Contrary to the above: . frandsfe~ .
- 1. On January 6,1995, the licensee failed to cmdir,ete a design change with an operational procedure change when PC/M 109-294 )
[Setpoint change to the Hydrazine Low Level Alarm (LIS-07-9)] was completed without assuring that affected procedure ONOP 2-0030131, )
" Plant Annunciator Summary," was revised. This resulted in !
annunciator S-10, "HYDRAZINE TK LEVEL LO," showing an incorrect l setpoint of 35.5 inches in the procedure. j
- 2. On May 16, 1994, the licensee failed to perform an adequate l independent verification of design output in the implementation of l PC/M 341-192 [ICW Lube Water Piping Removal and CW Lube Water i Piping Renovation). The as-built Dwg. No. JPN-341-192-008 was not :
incorporated in Dwg. No. 8770-G-082, " Flow Diagram Circulating ~ and l Intake Cooling Water System," Rev 11, sheet 2 issued May 9, 1995 i for PC/M 341-192. This resulted in Dwg. No 8770-G-082 erroneously i showing valves I-FCV-21-3A & 38 and associated piping still j installed.
- 3. On February 14, 1994, the licensee failed to coordinate a design.
change with an operational procedure change when PC/M 268-292 [ICW Lube Water Piping Removal and CW Lube Water Piping Renovation) was completed without assuring that affected procedure ONOP 2-0030131,
" Plant Annunciator Summary," was revised. This resulted in annunciator E-16, " CIRC WTR PP LUBE WTR SPLY BACKUP IN SERVICE,"
incorrectly requiring operators verify the position of valves MV-21-4A & 4B following a SIAS signal usir:g control room indication. These valves no longer received a SIAS signal, were deenergized and had no control room position indication. I
- 4. On October 28, 1992, the licensee failed to coordinate a design change with an operational procedure change when PC/M 275-290
[FIS-14-6 Low Flow Alarm and " Manual" Annunciator Deletions] was . completed without assuring that affected procedure ON0P 2-0030131, l
" Plant Annunciator Summary," was revised. This resulted in safety-related annunciators LA-12, "ATM STM DUMP MV-08-18A/18B 4 OVERLOAD /SS ISOL," and LB-12, "ATM STM DUMP MV-08 19A/19B !
OVERLOAD /SS.ISOL," incorrectly requiring operators to check i Auto / Manual switch or switches for the MANUAL position. The relay 1 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE 1
].. .. i t contacts which energized these annunciators based on switch
- position were removed to eliminate nuisance alarms. ,
i 5, On May 12, 1996, the licensee failed to coordinate a design change
- with an operational procedure change when Unit I fuel offload was '
- commenced without incorporating the prerequisite conditions ,
i contained in PC/M 054-196, supplement 0, "St. Lucie Unit 1 Cycle . 14 Reload," into OP 1-1600023, " Refueling Sequencing Guidelines." ; As a result, requirements for the operation of two Spent Fuel Pool Cooling Pumps, maximum initial Spent Fuel Pool temperature, minimum time since shutdown, minimum Component Cooling Water a system flow to the Spent Fuel Pool heat exchangers, and J operability of control room annunciation were not verified prior i i to the initiation of fuel offload (minimum requirements for i operating Spent Fuel Pool pumps and component cooling water flow were not met at the time fuel movement was initiated). l I g"
, i 1
) , 1 l 1. 1 e i n I l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
n- . . - - - - - - - - -
-\
/ ENFORCEMENT ACTION WORKSHEET nars=
ww% peob w%.pfs A U cma. % , (ST LUCIE OVERDILUTION EVENT) W*' w /W-u , PREPARED BY: R. Schin DATE: February 5, 1996 ""
.xitL LT1 This Notice has been reviewed by the Branch Chief or Divish n/ Director and each violation includes the appropriate level of sp f Vastohowand when the requirement was violated.
M 1gnature ' Facility: St. Lucie Unit (s): 1 l Docket Nos: 50-335 License Nos: DPR-67 Inspection Report No: 50-335,389/96-01 j Inspection Dates: Janusry 26-50, 1996 ) Lead Inspector: R. Schin
- 1. Brief Summary of Inspection Findings: :
Concern with operator attentiveness related to a reactivity addition ! event, and related operator violations of procedures:
- a. Operators failed to stop dilution when the proper amount I,sd b2en added.
4 b. The: 1 was inadequate watch turnover for the operator at the con..'ols during dilution. j c. Operators failed to follow the Conduct of Operations procedure in performing the dilution procedure (lack of strict / verbatim I compliance).
- d. Operators failed to adequately report the event to licensee ,
management. Also, operators exceeded the steady state licensed power limit of 2700 megawatts thermal (100% power).
- In addition, the licensee nade a change to the procedures as described i in the SAR without a 10 CFR 50.59 safety evaluation. !
See the attached draft NOV, General Descripf. ion of Event, Detailed i Sequence of Events, Summary of Draft Preliminary Inspection Findings, 1 Control Room Diagram, CVCS Charging System Diagram, Procedures, and l I FSAR. Y PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE h '
- _ -- . .- . - - __ .- - - _ - - =. . .- --
2
; 2. Analysis of Root Cause:
Operator inattentiveness to reactivity addition. Basis for Severity Level (Safety Significance): 3. I.C.3 Inattentiveness to duty on the part of licensee personnel, while j adding reactivity to the reactor, and J I.C.7 A breakdown in the control of licensed activities involving a
- number of violations that are related that collectively represent a
, significant lack of attention or carelessness toward licensed responsibilities.
- 4. Identify Previous Escalated A:: tion Within 2 Years or 2 Inspections?
EA 95-180 (EEI 95-16-01); LTOP inoperability due to PORY failure Event date 8/9/95
- 5. Identification Credit? No
- Identified through an event. The licensee initiated an In-House Event i Report and gave a copy to the NRC resident inspector promptly after the event. The event occurred at approximately 0220 on January 22, 1996.
Missed opportunities:
- a. In response to SOER 94-02, dated September 1994, which described a
- similar Turkey Point overdilution event and several inadvertent dilution events at other utilities, the licensee reviewed the St. Lucie operating procedures related to dilution and concluded that no changes were needed. This was a missed opportunity to strengthen operating procedures to prevent the 1/22/96 overdilution event. ,
- b. The Unit 2 dilution procedure had been changed in December 1995, but not the Unit 1 procedure, to more accurately describe dilution the way the operators had performed it for years (in manual and ,
direct to the charging pumps). During the event, manual dilution could not be accomplished by using the Unit 1 procedure in compliance with the Conduct of Operations (strict / verbatim compliance).
- 6. Corrective Action Credit? Yes The licensee initiated an In-House Event Report summarizing the event and began distribution of that report within about four hours after the event. The licensee also immediately removed the reactor operator who had initiated the event from licensed duties, promptly issued a Night Order and conducted training on the event with operators on each shift; revised the Unit 1 procedure for dilution so that manual dilution could be performed by strict compliance to the procedure steps; revised the Conduct of Operations procedure to require the R0 to get prior approval PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
!~ 4 3 3- -l l- from the SRO for dilution /boration, the SRO to directly. supervise i dilution /boration, no RO or SRO turnover during dilution /boration, and
- RTGB walkdown prior to RO or SR0 short term relief; and initiated l' ,
further review of the event. I 1 i ' Weaknesses'in the licensee's corrective actions included: 3-t a. Potential VIO of 10 CFR 50.59: The revised procedure (after the , event) did not support the FSAR Chapter 15 accident analysis ; assumptions on how dilution was performed. The revised procedure ! i described dilution in manual (with no automatic shutoff) and ; directly to the suction of the charging pumps. The FSAR assumed ! ! dilution in automatic (with an' automatic shutoff) and to the VCT ! ' (where the demineralized water would mix with boric acid solution ! ,' before going to the suction of the charging pumps and result in a
- lower rate of reactivity addition). The licensee had not
! performed a safety analysis of this difference and had not revised 3 the procedure and/or FSAR to make them agree. q i b. The revised procedure for manual dilution (after the event) did j not require the operator at the controls to remain by the dilution- l controls and to closely monitor the dilution during a manual i dilution with no automatic shutoff. l
- c. The licensee initial investigation of the event was not thorough l in that it concluded that maximum reactor power was 100.2%. i
. Subsequent review by the NRC and lice.1see found that maximum 3 reactor power was approximately 101.18%. l
- 7. Candidate For Discretion? (See attached list) Yes - potential 4 escalation. j i During the last year, the licensee's performance in-Operations has
! declined from SALP. I to SALP 2 (predecisional). There have been several operator violations of procedures that are, fr. part, related to the current violation:
- 1) VIO 335/94-22-02, " Improper Modification of Control Room Logs",
November 25,.1994 l
- 2) NCV 335/95-07-01, " Failure to Follow Shutdown Cooling Operating Procedures", April 19, 1995
- 3) .VIO 335/95-15-01, " Failure to Follow Procedures and Block MSIS Actuation", October 16, 1995 ,
- 4) VIO 335/95-15-02, " Failure to Follow Procedures during RCP Seal restaging", October 16, 1995
- 5) VIO 335/95-15-03, " Failure to Follow Procedure and Document abnormal valve position in the Valve Switch Deviation Log",
October 16, 1995 , PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
._ _ . . . _ _ . ._ _ . - _ . _ _ _ _ _ _ _ . _ . _ _ _ _ _. _ m . _ _ .
i 4 i !
- 6) VIO 335/95-15-04, " Failure to Follow Procedures during Alignment i
! of Shutdown Cooling System", October 16, 1995 l 4
- 7) VIO 389/95-18-01, " Failure to Follow Procedures and Maintain
[ 1 Current and Valid Log Entries in the Rack Key Log and Valve Switch Deviation Log", November 27, 1995 l
~
l
- 8) VIO 389/95-21-02, " Failure to Follow the Equipment clearance Order
_ l
- Procedure and Require Independent' Verification of a TS Related Component", December 8, 1995 All' of the above VIO/NCVs involved lic.ensed operators with a licensee j
4 corrective action commitment to stric6 adherence to procedures. i i 8. Is A Predecisional Enforcement Conference Necessary? I
- j. Yes t
Why: . There is substantial interest in this event and in the NRC message , i to the licensee and to the industry. The message for this enforcement i , action should be that operators must treat Dilution /Boration as , seriously as control rod manipulations. Also, that unusual operations '
- events must be transmitted promptly to management.
i j If yes, should OE or 0GC attend? Yes Should conference be closed? No
- 9. Non-Routine Issues / Additional Information: !
- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: . I.C.3 Basis for Inconsistency With Previously Issued Actions. (Guidance) l
- 11. Regulatory Message: The message for this enforcement action should be that operators must treat Dilution /Boration as seriously as control rod manipulations. Also, that unusual operations events must be transmitted promptly to management.
- 12. Recommended Enforcement Action: SLIII with CP
- 13. This Case Meets the Criteria for a Delegated Case. No
- 14. Should This Action Be Sent to OE For Full Review? No, informal review.
- 15. Regional Counsel Review To be determined at a later date.
No Legal Objection Dated: PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE i i
I-5
- 16. . Exempt from Timeliness: No Basis for Exemption: -
Enforcement Coordinator: DATE: L a l l l 1 l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
6 f ENFORCEMEN'T ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION E] Problems categorized at Severity Level I or II. [] Case involves overexposure or release of radiological material in excess of NRC requirements. ' [] Case involves particularly poor licensee performance. [] Case (may) involve willfulness. Information should be included to ! address whether or not the region has had discussions with OI regarding the case, whether or not the matter has been formally referred to 01, and whether or not 01 intends to initiate an investigation. A description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, willfulness, and/or management involvement should also be included. RE Current violation is directly repetitive of an earlier violation (in part). [] Excessive duration of a problem resulted in a substantial increase in risk. [] Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. ! [] Cases involves the loss of a source. (Note whether the licensee self-identif.ied and reported the loss to the NRC.) [] Licensee's sustained performance has been particularly good. [] Discretion should be exercised by escalating or mitigating to ensure that the proposed civil penalty reflects the NRC's concern regarding the violation at issue and that it conveys the appropriate message to the licensee. Exolain. l
)
)
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE MllTHOUT THE APPROVAL OF THE DIRECTOR, OE j
, 7 Enclosure 3 REFERENCE DOCUMENT CHECKLIST [] NRC Inspection Report or other documentation of the case: ! NRC Inspection Report Nos.: [] Licensee reports: ~ [] Applicable Tech Specs along with bases: [x] Applicable license conditions 4 [x] Applicable licensee procedures or extracts [] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test reruits 4 [x] Extracts of pertinent FSAR or Updated FSAR sections for citations involving 10 CFR 50.59 or systems operability [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections [] Other miscellaneous documents (List): PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
8 l 1 ! PROPOSED VIOLATION l l A. Technical Specification (TS) 6.8.1.a required that written procedures be i . established, implemented, and maintained covering the activities 4 recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February 1978. Appendix A includes operating procedures for the chemical and
- ' volume control system and administrative procedures for relief turnover, '
procedural adherence, and authorities and responsibilities for safe ] operation. Operating Procedure No. 1-0250020, Boron Concentration Control - Normal 4 Control, Rev. 35, step 8.5.14 required that operators monitor the water flow totalizer and close valve V2525 after the desired volume was added during a boron concentration dilution using the direct path to the charging pump suction. Administrative Procedure No. 0010120, Conduct of Operations, Rev 79, Appendix D, Crew Relief / Shift Turnover, required that, for short term watchstander relief, a turnover be conducted including: general ! watchstation status, off-normal conditions, and tests in progress. l l Administrative Procedure No. 0010120, Appendix M, Procedural Compliance l and Implementation, required that controlled procedures be implemented !
-and complied with in accordance with the instructions provided in QI 5- j PR/PSL-1. Procedure QI 5-PR/PSL-1, Preparation, Revision, Review / Approval of Procedures, Rev 67, Section 5.13.2, stated that all procedures shall be strictly adhered to and identified that Operating j Procedure 1-0250020 was not considered " skill of the trade" and was not !
to be performed from memory without referring to the procedure. Administrative Procedure No. 0010120, Appendix E, Notification of Operations Supervisor /FPL Management, required prompt verbal ! notification of the Operations Supervisor for unplanned reactivity changes. Contrary to the above:
- 1. On January 22, 1996, at approximately 2:30 a.m., Unit 1 operators failed to close valve V2525 after the desired volume was added during a boron concentration dilution using the direct path to the charging pump. Operators had desired to add between 25 and 40 gallons of primary makeup water, but failed to stop the dilution until approximately 400 gallons were added. During this time, the temporary relief operator at the controls was unaware that a boron concentration dilution was in progress, which resulted in an unmonitored reactivity addition. The SR0 and other operators in the control room were also unaware that a reactivity addition was in progress.
- 2. On January 22, 1996, at approximately 2:30 a.m., the Unit 1 operator at the controls conducted a short term watchstander relief with an inadequate turnover in that it failed to include general watchstation status and conditions including that a boron PROPOSED ENFORCEMENT ACTION . NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
t 9 concentration dilution was in progress. As a result, the relief i operator at the controls was unaware that a boron concentration , l dilution was in progress and failed to adequately monitor and l control the dilution.
- 3. On January 22, 1996, at approximately 2:30 a.m., operators performed Operating Procedure 1-0250020 from memory, without referring to the procedure, and without strictly adhering to the procedure. At the time, the procedure was written such that the boron concentration dilution that was performed could not have be n performed by strictly adhering to the procedure.
- 4. On January 22, 1996, between 2:30 a.m. and 7:20 a.m., operators failed to give prompt verbal notification to the Operations Supervisor for unplanned reactivity changes that had occurred.
B. The Facility Operating License for St. Lucie Unit I authorizes the licensee to operate the facility at a steady state reactor core power level not in excess on 2700 megawatts thermal (MWt). TS 1.25 defines rated thermal power to be a total r.eactor core heat transfer rate to the reactor coolant of 2700 MWt. TS 1.33 defines thermal power to be the total reactor heat transfer rate to the reactor coolant. Contrary to the above, on January 22, 1996, b:: tween approximately 2:20 and 3:30 a.m., the reactor core therma'l power level limit of 2700 MWt (100%) was exceeded, due to operator inattentiveness. 100% reactor power was exceeded for approximately 70 minutes. Also, 101% reactor power was exceeded for approximately 4 mir.utes and a peak reactor power of approximately 101.18% was reached. 1 C. 10 CFR 50.59 allows the licensee to make changes to the procedures as ; described in the Safety Analysis Report (SAR), without prior Commission ; approval, unless i.ne change involves, in part, an unreviewed safety question. A proposed change shall be deemed to involve an unreviewed safety question if, in part, the probability of occurrence of an accident important to safety previously evaluated in the SAR may be increased. The licensee shall maintain records of changes in procedures made pursuant to this section, to the extent that they constitute changes in procedures as described in the SAR. These records must include a written safety evaluation which provides a basis for the determination that the change does not involve an unreviewed safety question. Contrary to the above, on January 23, 1996, the licensee made a change in Unit 1 procedures as described in the SAR and the records for that change did not include a written safety evaluation. Temporary Change 1-96-017 to procedure 1-0250020, Boron Concentration Control - Normal Operation, Rev. 35, added instructions for dilution in manual and I directly to the suction of the charging pumps. However, the SAR, ! paragraph 15.2.4.1, states that boron dilution is conducted under strict i administrative procedures which limit the rate and magnitude of any i required change in boron concentration. Further, the SAR states that boron dilution must be conducted in automatic (such that when the j l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE l i
- )
i ! a 10 ,. specific amount has been injected, the demineralized water control valve
- is shut automatically) and describes introduction into the volume ,
i control tank (VCT). The SAR concludes that, in part, because of the , procedures involved, the probability of a sustained or erroneous dilution is very low. The licensee implemented Temporary Change 1 . j 017 on January 23, 1996, without a written safety evaluation. ! 1 1
- ' General Descriotion of the Event J
! At approximately 0225 on January 22, 1996, the Unit I control board Reactor 4 Controls Operator (RCO) began a manual dilution to the RCS by aligning primary makeup water (demineralized water) directly to the suction of the IB Charging i Pump. Moments after beginning the dilution, the board RCO responded to a secondary plant annunciator and then saw the desk RCO return from the kitchen. i He requested that the desk RCO relieve him so that he could prepare his lunch. l During the turnover, there was no discussion of the dilution in progress.
- Following the turnover, the relief operator at the controls and the Nuclear Plant Supervisor (NPS), who was at the desk RCO station, were not aware that a dilution was in progress. The original board RCO returned between 5-10
! minutes later and immediately recognized his error. He informed the other RCO l of the overdilution, which was overheard by.the NPS, and stopped the dilution. i The NPS directed the ANPS take charge and begin a manual boration. Unit 1 entered 2-hour TS LC0 Action Statement 3.2.5 for T, greater than 549"F. The I maximum T, obtained was 549.9'F and the maximum reactor power was 101.18%. T,- < was above the TS limit _of 549'F for approximately 50 minutes and reactor power ! was above 100% for approximately 70 minutes. The TS LCO Action Statement for i
- T, was not exceeded and the guidance of the Jordan memorandum on maximum l reactor power was not exceeded. The operators did not verbally notify plant
- management or the NRC of this event.
1 Detailed Seouence of Events (Note that the times for the sequence of events are approximate and only relevant events are mentioned) 1/21/96 l 11:00 p.m. Incoming mid shift assumed Unit I responsibility with the Unit at l 100% power, 870 MWe, Tavg at 575 degrees F, Thot at 600 degrees F, ' Tcold at 548.9 degrees F, RCS Boron concentration at 376 ppm, Xe worth at -2722 pcm, all CEAs fully withdrawn and manual, and no Technical Specification action statements in effect. Major ;
. evolution planned for the shift was to place the waste gas system in service. Further, there was an annunciator alarm E-9 associated with circulating water pump lube water supply strainer delta P high that was intermittently coming in due to a failed pressure switch..
11:45 p.rr.. Board RCO reset to zero the primary water (to VCT or charging pump) flow totalizer in preparation for inventory balance (RCS PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
l i { - 11 l [ leak rate calculation) 11:00 p.m.- 2:00 a.m The board RCO recalled performing at least two dilutions of l approximately 35 gallons each between 11:00 p.m. and 2:20 a.m. l l without resetting the totalizer. ! l l' 1/22/96 i xx:xx a.m NPS arrived in Unit I control room to gather data for morning report meeting and sat near desk behind control boards. STA was also present near NPS xx:xx a.m. ANPS turned over control room senior reactor operator responsibility to NPS and proceeded to the kitchen to prepare breakfast xx:xx a.m. Desk RCO left control room to go to the kitchen ~ 2:20 a.m. Normal continued fuel burnup resulted in indicated Tc of_548.7 degrees F on RTGB-104 (digital meter). At this point the board RCO decided to restore Tc to maximum allowable program value of 549.0 degrees F. xx:xx a.m. Desk RC0 arrived in the control room with his meal 2:25 a.m. The board operator began a manual dilution by aligning primary water to the suction of the charging pumps by opening FCV-2210X ! and A0V-2525. The flow rata was approximately 44 gpm. 2:26 a.m. Annunciator E-9 associated with circulating water lube water supply strainer high delta P was received. The board RCO walked to the panel and acknowledged the_ annunciator. l l 2:27 a.m. After acknowledging the annunciator, the board operator decided to proceed to the kitchen to prepare his meal. The board operator conveyed this to the desk operator and requested that he take over the board operator responsibilities. However, he did not mention the ongoing dilution. .The desk operator got up and proceed to the board in the vicinity of panel 103. The original board operator proceeded to the kitchen and started preparing his meal on a skillet that had been kept warm. At this time the NPS and the STA were in the control room at the desk area. The NWE had been in and out of the control room throughout the shift. The relief operator at the controls, NPS, STA, and NWE were not aware of the ongoing dilution. ) 1 2:35 a.m. The original board operator returned from the kitchen with his meal. Upon approaching the board, he realized that he had left the control room with an ' ongoing manual dilution. He exclaimed that he had overdiluted and immediately began securing the dilution. The desk operator questioned how much water was added and the board operator noted from the totalizer that approximately PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE _ _ _ - _ , _ -. _ _i
l l 12 l 400 gallons was added. l 2:35 a.m. Soon after, annunciator M-16 associated with RCP controlled bleedoff pressure high was received. At this point the Tc was noted by the desk operator to be 549.6 degrees F. Entry into two hour action statement associated with Technical Specification : 3.2.5, DNB paramenters was recognized and later logged. 2:36 a.m. The desk operator directed the board operator to initiate boration to restore Tc to program. The NWE calculated the amount of borated water to be added to the RCS. The NPS asked the desk operator to notify the unit ANPS to come to the control room. x:xx a.m. ANPS walked into the control room. 2:41 a.m. Tc reached the highest noted value of 549.9 degrees F. MWe reached 875 and indicated reactor power was approximately 101.2% x:xx a.m. Operator secured boration. 3:14 a.m. Tc noted below 549.0 degrees F. Technical Specification action statement was exited. x:xx a.m. STA initiated an In-House Event Report and notified HPES personnel by telephone. 5:45 a.m.- , 6:00 a.m. Shift turnover occurred. It appears that the dilution event was not discussed with the oncoming shift. 6:25 a.m. In-House Event Report was E-mailed to standard distribution, which included plant management, by the STA. 6:30 a.m. The Operations Manager toured the control room but was not informed of the over dilution event. 7:20 a.m. The Operations Manager read the control room logs (in his office I by computer) and questioned the log entry associated with the overdilution event. ' 7:30 a.m. Licensee initiated a detailed investigation associated with the event. l l 7:45 a.m. Senior Plant management was notified.of the event during the i morning meeting. 10:00 a.m. NRC resident inspector was given the event report that was initiated associated with the event. PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
13 ST. LUCIE ONSITE EVENT FOLLOWUP INSPECTION OVERDILUTION EVENT of 1/22/96 (Exit was at 10:00 a.m. on 1/30/96) Inspectors: R. Schin, S. Sandin, B. Desai Summary of draft oreliminary findinas:
- 1. Magnitude of power and temperature excursion
- a. Reactor power Peak reactor power was approximately 101.18%
100% power was exceeded for approximately 70 minutes . 101% power was exceeded for approximately 4 minutes The event was within the accident analysis The guidelines of the Jordan memo were not exceeded
- b. Cold leg temperature Peak Tc was approximately 549.9 degrees F TS limit of 549 was exceeded for approximately 50 minutes TS 2-hr. action statement was properly entered and was not !
exceeded j
- 2. Concern with operator attentiveness - Potential / Apparent VIO of )
procedures (Enforcement panel form completed on this issue): j
- a. Operators failed to stop dilution when the proper amount had been j added.
]
- b. There was inadequate watch turnover for the operator at the l controls during dilution. '
- c. Operators failed to follow the Conduct of Operations procedure in performing the dilution procedure.
1
- d. Operators failed to adequately report the event to licensee management.
- 3. Concern with control room command and control - Weakness
- a. The SR0 in the control room was not aware of the dilution in progress.
- b. The board operator did not inform the SR0 of dilution - this was a general practice at the site and not. required by procedures.
- c. The watchstander board was not maintained (on Saturday).
- d. The SRO in the control room was allowed to be in the ANPS office for unlimited time, out of sight of control room activities and out of hearing range of almost all control room activities except annunciator alarms (not applicable during this event).
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
m 11
- 4. . Weaknesses in procedures
- a. The' Unit 2 dilution procedure had been changed, but not the Unit I procedure, to more accurately describe dilution the way the operators had performed it for years (in manual.and direct to the charging pumps). During the event, manual dilution could not be accomplished by using the Unit 1 procedure in compliance with the Conduct of Operations.
- b. Procedures and practices for dilution (before and during the event) did not support the FSAR accident analysis assumptions on how dilution was performed. The FSAR assumed dilution in automatic and to the VCT.
- c. Procedures for dilution (before and during the event) did not.
require the operator at the controls to remain by the dilution controls and to closely monitor the dilution during a manual dilution with no automatic shutoff.
- 5. Weaknesses in corrective action
- a. Potential VIO of 10 CFR 50.59: Revised procedure (after the 1
' event) did not support the FSAR Chapter 15 accident analysis ;
assumptions on how dilution was performed. .The FSAR assumed i dilution in automatic and to the VCT. o l
- b. The revised procedure for manual dilution (after the event)'did !
not require the operator at the controls to remain by the dilution i controls and to closely monitor the dilution during a manual dilution with no automatic shutoff. I l
- c. The licensee initial investigation of the event was not thorough in that it concluded that maximum reactor power was 100.2%. '
Subsequent review by the NRC and licensee found that maximum reactor power was approximately 101.18%.
- 6. Weakness in Operational Experience Feedback l
- a. In response to SOER 94-02, dated September 1994, which described a similar Turkey Point overdilution event and several inadvertent dilution events at other utilities, the licensee reviewed the St.
Lucie operating procedures-related to dilution and concluded that no changes were needed. This was a missed opportunity to strengthen operating procedures to prevent the'1/22/96 overdilution event. .
- 7. Other comments
- a. There was no clearly noticeable indication of dilution in progress. The dilution clicker was quiet (might not be heard from the desk area) and sounded identical to the nearby clickers that.
routinely made noise. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPh0 VAL OF THE DIRECTOR, OE
d l!i
- b. Operators routinely did not log reactivity additions; however, the licensee's Conduct of Operations procedure stated that operators should log reactivity changes..
LICENSEE DISSENTING COMENTS l' 1. The licensee had dissenting comments on item 5.a. above, the potential violation'of 10 CFR 50.59. The inspectors told the licensee at the exit that'those dissenting comments would be included in the inspection report, for further review by NRC management. The dissenting comments, from the engineering manager (Dan Denver) and the licensing manager (Ed Weinkam), included: 'l I
- a. The previous procedure allowed diluting in manual and directly to i the suction of the charging pumps, and that had been the practice '
for many years. Therefore, the temporary change on 1/23/96 (after the event) did not change the method of dilution, but only clarified a previously existing procedure and made it conform to
" verbatim compliance" rules. The inspectors did not disagree.- In fact, further review, as requested by the inspectors, found that the first time the dilution procedure was changed to allow opening .
of valve 2525 (directly to the suction of the charging pumps) was ' in a change to rev. 2 of the procedure, in 1976, before the operating license was issued.
- b. The design of the plant (piping, valves) always was such that dilution in manual and-directly to the suction of the charging pumps was possible. The inspectors did not disagree. l l
- c. The accident analysis assumed a worst case dilution event with i demineralized water going directly to the suction of the charging '
pumps and three charging pumps running. That would be three times l the flowrate of this event and therefore that analysis bounds this 1 event. The inspectors did not' disagree. l
- d. The FSAR Chapter 9 description of the' Chemical and Volume Control System did not prohibit dilution in manual and directly to the suction of the charging pumps. The. inspectors did not disagree.
- e. The automatic mode of dilution is less safe than the manual mode, in that there is more opportunity for a malfunction that could -
result in a maximum flowrate approaching the design limit. The inspectors did not comment on that position.
- f. The procedure change that first allowed dilution directly to the suction of the charging pumps was made before.the operating license was issued, therefore 10 CFR 50.59 did not apply to that change. The inspectors did not comment on that position.
- g. Since the operating procedure that was in effect at the time the operating license was issued allowed dilution in manual and l
directly to the suction of the charging pumps, that method was PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR, OE
E ; , included in the original licensing basis of the plant. The , inspectors'did not agree with that position.
- h. After receiving.these licensee comments, the inspectors' concern l
! remained unchanged: The Temporary Change of 1/23/96 (after the , event) described procedure steps for dilution in manual and directly to the suction of the charging pumps. That procedure was different from the one described in the FSAR. The licensee's procedure differed from the FSAR in that it allowed a faster rate of reactivity addition and without an automatic shutoff. The licensee had not performed a safety analysis of this difference j and had not revised the procedure and/or FSAR to make them agree.
- 2. The licensee also had a dissenting comment on item 5.c. above, the
. weakness in the licensee's initial investigation. The dissenting comment, from the Plant Manager (Jim Scarola), was: l a. The initial investigation, for the In-House Event Summary, was done by the STA. Timeliness was more important than quality at i that time. Subsequent more thorough review would be performed by
- the licensee. The inspectors acknowledged the licensee's comment.
i i l I 1 PROPOSED ENFORCEMENT ACTION . HOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE <
J
/
- f _
3-h Proposed Operator i NOTICE OF VIOLATION Docket No. 55-License No.0P-EA(s) TBD During an NRC inspection conducted on January 26-30,.1996, violations of NRC requirements were identified. In accordance with the " General-Statement of Policy and Procedure for NRC Enforcement Actions," NUREG-1600, the violations are listed below: Technical Specification 6.8.1.a required that written procedures be established, implemented, and maintained covering the activities
- recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February 1978. Appendix A includes operating procedures for the chemical and ;
volume control system and administrative procedures for relief turnover, ' procedural adherence, and authorities and responsibilities for safe operation. Operating Procedure No. 1-0250020, Boron Concentration Control - Normal Control. Rev. 35. step 3.5.14 required that operators monitor the water ! flow totalizer and close valve V2525 after the desired volume was added during a boron concentration dilution using the direct path to the , charging pump suction. .l 1 Administrative Procedure No. 0010120, Conduct of Operations, Rev 79, Appendix. D, Crew Relief / Shift Turnover, required that, for short term watchstander relief, a turnover be conducted including: general watchstation status, off-normal conditions, and tests in progress. Administrative Procedure No. 0010120., Appendix M, Procedural Compliance and Implementation, required that controlled procedures be implemented and complied with in accordance with the instructions provided in QI 5-PR/PSL-1, Preparation, Revision, Review / Approval of Procedures, Rev 67. Procedure QI 5-PR/PSL-1 Section 5.13.2, stated that all procedures shall be strictly adhered to and specifically identified that Operating Procedure 1-0250020.was not considered " skill of the trade" and was not to be performed from memory without referring to the procedure.
~ Contrary to the above:
- 1. On January 22, 1996, at approximately 2:30 a.m., the Unit 1 operator failed to close valve V2525 after the desired volume was
.added during a boron concentration dilution using the direct path to the charging pump. The operator had desired to add between 25 and 40 gallons o_f primary makeup water, but failed to stop the dilution until approximately 400 gallons were added. During this time, the~ temporary relief operator at the controls was unaware that a boron concentration dilution was in progress, which resulted in an unmonitored reactivity addition. The SRO and other operators in the control room were also unaware that a reactivity addition was in progress.
) 1 $ 2. On January 22, 1996,-.at approximately 2:30 a.m.,-the Unit 1 operator at the controls conducted a short term watchstander relief with an inadequate turnover in that he failed to include 4 general watchstation status and. conditions including that a boron l concentration dilution was in progress. As a result, the relief l operator at the controls was unaware that a boron concentration dilution was in progress and failed to adequately monitor and control the dilution. i'
'3. On January 22, 1996, at approximately 2:30 a.m., the Unit 1
! operator. performed Operating Procedure 1-0250020 from memory, i' without referring to the procedure, and without strictly adhering to the procedure. At the time, the procedure was written such that the boron dilutian that was performed could not have been 4 performed by strictly adhering to the procedure. ) These violations represent a Severity Level III problem (Supplement ). l
- j. Pursuant to the provisions of 10 CFR 2.201, ************* is hereby required I 4
to submit a written statement or explanation to the U.S. Nuclear Regulatory l 4 Commission, ATTN: Document Control Desk, Washington, D.C. 20555 with a copy l l to the Regional Administrator, Region II, and a copy to the NRC Resident )
. Inspector at the facility that is the subject of this Notice, within 30 days l of the date of the letter transmitting this Notice of Violation (Notice).
i This reply should be clearly marked as a " Reply to a Notice of Violation" and l should include for each violation: (1) the reason for the violation, or, if i contested, the basis for disputing the violation, (2) the corrective steps ! that have been taken and the results achieved, (3) the corrective steps that l will be taken to avoid further violations, and (4) the date when full compliance will be achieved. Your response may reference or include previous ! -docketed correspondence, if the correspondence adequately addresses the j- required response. If an adequate reply is not received within the time
- specified in this Notice, an order or a Demand for Information may be issued ,
j as to why the license should not be modified, suspended, or revoked, or why ' such other action as may be proper should not be taken. Where good cause is j shown, consideration will be given to extending the response time. ! Under the authority of Section 182 of the Act, 42 U.S.C. 2232, this response ! shall be submitted under oath or affirmation. Because your response will be placed in the NRC Public Document Room (PDR), to I l- the extent possible, it should not include any personal privacy, proprietary, i j or safeguards information so that it can be placed in the POR without , i redaction. However,.if you find it necessary to include such information, you ! [ should clearly indicate the specific information that you desire not to be
- placed-in,the PDR, and provide the legal basis to support your request for i withholding the information from the public.
i Dated at Atlanta, Georgia i this day of Februay 1996 i F
Page 91 of 174 , 1 ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 CONDUCT OF OPERATIONS , FIGURE 3
~
hb ! NWE OFFICE g ESFAS gy7 gj ,
%4 & a O f (D l 106 105 U (P W to V b{y c3 ;
g- [104 Og m l
~
p$ .- ,
. 103 i .
('k O
- h. w
- n. g,
(?I Y) 1 1I l i i E (p '. 102 d ; l V1 2 i i o 0 i ares s Y, f Fj i O ,' 101 g i 4 i C/ i i
- o o $$ fog 9St ,
= ,'
,4 g gg .
U, l ENTRANCE a kh*g f . V - v,a O,l; 7> I ANPs OFFICE
; LRP CRAC PNL PAP sa E ,
i
' N 1
K4 g['Igk) a d-
\-
7 7 - g-(@ C s l
7 i n E t a f, ' e fl;! ~ h *l D., e.
- gI 8:!Ee i8 :g, .
X
.g: [t e
[gg I reg.,li 3 o l jgE E ! I; i q1- i
*9llE 3
I< 7.t IV
$t
- E W E 'I F I t*8 EF Y_ g g g *~ g ~* .
s
, g si - -c + j. *-- .
- ! 9! @!
A a k+-is I I J::til .. ._ I=0 mi e ee:a E 1
!4: b,i ' t e v g et 5
N 'hfX l I l lEH: ,l'i.f g i. ' i
~ 5 -. 4 ga t ll1 &
t t Y k .__ 4: i t E I i, eh , e ,g i, el's = i 81 , ! 8! w e c_-_, & 4 e c_, 4
.e , - .,
k I I g, I lI f It ' i
, 3g .
O IE l----- J8 si L' ____. J g ' l cc L__________ _ _ _______, _' ; l i e-
-r W l l U" f %
to IS 1 U l
> ill . ate U
l Page 1 of 20. ._ . FLORIDA POWER & LIGHT COMPANY ST. LUCIE UNIT 1 .- E t OPERATING PROCEDURE NO. 1-0250020 j , pse- . REVISION 35 ( w
1.0 TITLE
' l BORON CONCENTRATION CONTROL - NORMAL OPERATIOh rmy' 2.0 REVIEW AND APPROVAL:
Reviewed by Plant Nuclear Safety Committee 5/30 1974 Approved by K.N. Harris Plant General Manager 6/31974 Revision 35 Reviewed by Facility Review Group 8/10 & 8/17 1995 Approved by C.L.Bunon Plant General Manager 8/17 1995
3.0 PURPOSE
' This procedure establishes a method of operation to supply makeup water to the Reactor Coolant System (RCS), Safety injection System and Refueling Water Tank l (RWD at a cesired boron concentration and provides instructions for the following I modes of control: 3.1 BORATE I i 3.2 DILUTE - 3.3 MANUAL 1 3.4 AUTOMATIC 3.5 Shutdown Cooling (SDC) Boron Concentration Control l 4 S1 OPS DATE COCT PROCEDURE DOCN 1-0250020 SYS COMP COMPLETED ITM 35
i Pcge 14 of 20- ,, ST. LUCIE UNIT 1 ! OPERATING PROCEDURE NO. 1-0250020.- REVISION 35 h"' , SORON CONCENTRATION CONTROL - NORMAL OPERATION 8.0 . INSTRUCTIONS: (continued) ! 8.4 ' (continued) c
^
i
- 3. o.
Enter the number of gallons to be added into the PMW Batch integrator-il . i and set desired flow rate on FRC-2210X (Makeup Water Flow). " i
- 4. Start one Primary Water Pump if not running.
l
- 5. Place V2512 in the OPEN position.
i
- 6. \
Place Mode Selector switch in DILUTE and observe flow indication of FRC-2210X.
- 7. I Monitor VCT level to ensure tank oces not fill up to high level alarrn. For j
extenced dilutions, match makeuo flow with charging flow using the PMW j makeup flow controller to prevent over-filling the VCT while diverting letdown. B. Upon completion of dilution, retum V2512 control swen to AUTO or CLOSED position. 9. Return Mode Selector Switch to AUTO or MANUAL.
- 10. Ensure tnat the desired reactivity change occurs.
8.5 Manual Mode of Operation
- 1. '
Determine the desired volume to be added to the VCT and calculate the ! proper blend ratio using the most recent chemistry boron samples of the 3 1 A or 1B BAMT and the RCS. If the chemistry sample for.the RCS is not available then use the boronometer reading. [ l I 1
Page 15 of 20 ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-0250020 REVISION 35 M BORON CONCENTRATION CONTROL - NORMAL OPERATION
8.0 INSTRUCTIONS
(continued) ' i 8.5 (continued) ' c r' 3
..? '
1 INI.fr. . Ei i The following formulas can be used to determine volume and blend ratio. Remember to make note of the current totalizer readings. 3 t
.\
Volume to be added = desired VCT level % - actual VCT level % X 33.8 gal /%. a f d Blend ratio = BAMT Concentration divided by RCS Concentration minus one BAMT-1 l RCS I. 2. Ensure Mode Select switch is selected to MANUAL.
- 3. 0 Place FRC-2210Y and FRC-2210X to manual and close FCV-2210Y ! a FCV 2210X by taking the controller output to zero.
4. Ensure 1 A or 1B primary water pump is running. 5. Ensure the BAM pump recirc valves V2510 and V2511 are open.
}
- 6. Start either the 1 A or 1B BAM pump.
- 7. Open the Boric Acid Makeup isolation valve FCV-2161. I
- 8. Ensure FCV-2210X, Reactor Makeup valve, selector switch is in AUTO. (
\
- 9. Ensure FCV-2210Y, Boric Acid valve, selector is in AUTO. >
- 10. \
If blending directly to the VCT, then open V2512, Reactor Makeup Water stop valve, t 11, if direct path to the charging pump suction.is desired, then open valve ' V2525, Boron Load Control Valve. M
i P ge 16 of 20- .! ST. LUCIE UNIT 1
=" '
OPERATING PROCEDURE NO. 1-0250020. REVISION 35 3ORON CONCENTRATION CONTROL ,40RMAL OPERATICN
8.0 INSTRUCTIONS
(continued) 4 8.5 (continued) CAUTION To preclude lifting the VCT relief valve while using V2525, do not allow the combined PMW and boric acid flowrates to exceed the running charging ' I pump (s) capacity. f 1 1
- 12. Adjust FRC 2210X and FRC-2210Y to the desired flow rates.
4 NOTE ; Monitor VCT levet for increase. I i NOTE The addition of Boric Acid should be completed before the PMW, such that. ' the total blend volume remaining allows for at least 30 gallons of pnmary i makeup water alone. to flow through the lines and flush out any remaining I i boric acid. ' t
)
13. When the desired amount of Boric Acid has been added, place the selector switch for FCV-2210Y to CLOSE. l
)' !
14. When the Boric Acid and water flow totalizers show that the proper h amounts have been added to the VCT, then close V2512 or V2525. which ' ever was used. , j
/
-p
- 15. 1 y Place the running BAM pump switch to AUTO and ensure pump stops.
- 16. Close FCV-2161.
- 17. Close FCV-2210X,
- 18. Monitor for any abnormal change in temperature. Check Boronometer for !
undesirable change in Boron Concentration.
QI 5-PR/PSL-1. . ..
~
l Revision 67-
- December,1995 Page 92 of 101 1
- RGURE 4 '
TEMPORARY CHANGE REQUEST l (Page 1 of 3) t A Refsisn, Intermation- (Originator to complete) ; St. Lucie Unt: # PSL i TC # IO ~ 00 ! l Procedure
Title:
13oeon CoucoswAm Ourhe - M5emme. d3mm.J _ l l Procedure Number: oP 1-easueJe Rev.- 3'f** Reason for change: 400 P12x4DutA<. GweeacC 152 CW:5 6 r w , m ofu' D J - l Aw da n ~ e The ecs . ks unwon na n w 1st m w. ,ar u of .2-W,25% ace; , REv 03,
- Originator
- 2 %NenA Phone: K b69 Date:JAo/ 23 /1974
! B Piccecurat Com d (Originator to complete)
- Yes N
- O l i .he intent of the procedure altered? (Tech. Spec. 6.8.3.A) If yes, a TC is NOT
, applicable. A PCR is required. O g is this Temporary change for a one time use? If yes, this TC can be executed gle, tirge,,, _ only, if no, this TC rnay be used up to 90 days, and the originator of the TC shall j suomit a procedure crange request incorporating this TC at the same time the TC is i approved. Department Head or Designee.! ,2 A C- b M I [LS/N O
- O y is this T.C. for a c.1.7 If yes, the Quality Manager or designee and the Dept. Head or -
i designee who is jurisdictionally responsible for the O.l. shall sign. Y l Quality Manager or Designee / / l Department Head or Designee / / C Temocrarv Chance Contents: (Originator to complete) i l Does this Change: Yes No f O [ Incorporate complex or extensive changes? If Yes, Subcommittee required. 4 Subcommittee initials O [ Modify instrument setpcints? l C % Delete an independent verification? O [ Alter a QC holdpoint?
. O y Modify a procedural step which alters a regulatory requirement as identified in the i procedure?
O g Alter the first execution of a procedure? (Preop, LO!) j O g Addition of any chemicals? l . NOTE
- if any of the above entena are marked yes, pner FRG review is required.
/R6'
QI 5-PRPSL-1 . j Revision 6T -I l; December,1995 i Page 93 of 101 j ' RGURE 4 i . TEMPORARY CHANGE REQUEST I \ (Page 2 of 3) ! D 10 CMI SQA8 Sersemng TC # I~ % ' 0'7 ! ! Yes No 1. Does the ehenge repmesm a change e sie leagly se descreed M em SAR7
- L Does me dange represent a enange to pmoedures as esserted M the SAR7 2.
l Is me enenge esecanese tuh a test or empenment riot desenbod in ess SAR7 I 4. Could the scienge esset nusmer eefety m a way not ;r -'; evalueled h enSAR7 h ~7 3. Does me ehenge recure a cmenge to me Tecnrucal W7 k. i i m if the answer to g the apove 10 CFR 50.59 scnsentng questsons are no. (Questions , j ; 1 5), then a safety evaketion,is ngsfecuired. l i E sTArowswtoyionnen Does rue anange: (NPS to kVf/b Mr % Date / A3,# Yes No !
- 1. Conipromme vie espereden of tems of eeusment?
L Potencedyimedens preamse [
- 3. Defeat summonc agrisee? I
- 4. Defeat anneneness or e6assical ineseces?
2
. 5. Aller sie asenp6seon of an evoluson as to en opere or wone rinsis.
I # f a If yee to No. 5. eumonseson imm me Plant General Manager or Site Ves Preement snell be otnames. g Osas / / j Yu M l C Prior FRG rewsw reounse?
- b. .
E 4 j i If any of theeove enteria are marked yes, discuss possible altomatives with the onginator. Q[ l O ,, - NPS 51gnease M i M >u' - Date I !"' m ) F FRG Renew- V i j Piere GenenM Manager Approval Dels 1 ' ! FRG Nwneet . 1 TNe enange ehes be rewowee (if pnar FRG towow a not i i recured) by me Femtdy Rowow Group ants approves try me Plant General Manager ' usewn 14 anye of me i 4 sumonzosen case. (Tech. Spec. 6A.3.C) a j REJECTED by FRG/Plers Gerwrel Manager - Date / _'-
; Reason. I' L .l Renan to Ortginosor 11is me responetsity of me onynotar of me resecree temporary cnenge to conce tne cnenge m the approonste Contred Room, easuoy ait nele comme one neit es suneeouere ovosumons uomo tne temporary enenge.
1
i
.QI 5-PRESLd . ...
Revision 67' - December,1995 ); Page 94 of 101 MGURE 4 TEMPORARY CHANGE REQUEST , l (Page 3 of 3)
- I 1
i I G i TC0 H & ,B!1
.6ggggg1: (This change shall have prior app b i management staff.) (Tech. Spec. 6.8 ) /.yg NPS and one membe/ of the plant Plant Management i L. k Date 1 / 33Sb NPS Signature b. m Authonzation Dab I /O/N
/
H Cancellation Authonzation * (NPS/ANPS) Date / / 4 l Reason: 1 i
,l 0
4 i ; j t i 1 i 4 l 1 l l l i ) i i i e
Paga 14 of 20 _, i . ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-0250020, REVISION 35 y j BORON CONCENTRATION CONTROL - NORMAL OPERATION =Pbl . 2 ' i ;'
8.0 INeTRUCTIONS
(continued) l 8.4 (contir.usd) ;
- 3. Enter the number of gallons to be added into the PMW Batch integrato and set desired flow rate on FRC-2210X (Makeup Water Flow). ,
j 4. Start one Primary Water Pump if not running.
- 5. Place V2512 in the OPEN position.
6. Place Mode Selector switch in DlLUTE and observe flow indication of [ FRC-2210X. i 3 7. Monitor VCT level to ensure tank does not fill up to high level alarm. For extended dilutions, match makeup flow with charging flow using the PMW makeup flow controller to provent over-filling the VCT while diverting letdown. B. Upon completion of dilution, retum V2512 control switch to AUTO or CLOSED position.
- 9. I Retum Mode Selector Switch to AUTO or MANUAL '
- 10. Ensure that the desired reactivity change occurs.
k I 3 8.5 Manual Mode of Operation n 1. Ma 2 Bld { y A$ Determine the desired volume to be added to the VCT and calculate the g proper blend ratio using the most recent chemistry boren samples of the N 1A or 1B BAMT and the RCS. If the chemistry sample for the RCS is not available then use the boronometer reading.
_q I I q _ _ . . _..P_agiL15 of @
}
}. .-
- ST. LUCIE UNIT 1 -
OPERATING PROCEDURE NO.1-0250020, REVISION 35 )
- .c.2
. BORON CONCENTRATION CONTROL - NORMAL OPERATION
. 4 ., , ,
i
8.0 INSTRUCTIONS
(continued) h.?lf-
- 5".
8.5 (continued) , V~'; - j .NJL!A The following formulas can be used to determine volume and blend ratio. 2$5 Remember to make note of the current totalizer readings. i 1 Volume to be added = desired VCT level % - actual VCT level % X 33.8 gal /% 1
)
Blend ratio = BAMT Concentration divided by RCS Concentration minus one g&MT,- 1 ! i i RCS a 1 8 p Ensure Mode Select switch is selected to MANUAL C $ Place FRC-2210Y and FRC-2210X to manual and close FC FCV-2210X by taking the controller output to zero.
>- @ Ensure 1 A or 1B primary water pump is running, y
t E-@ Ensure the BAM pump recire valves V2510 and V2511 are open . ! N ' i 6 @ Start either the 1A or 1B BAM pump. N@ Open the Boric Acid Makeup isolation valve FCV-2161. [ ( @ Ensure FCV-2210X, Reactor Makeup valve, selector switch is in AUT I I 8 f-@ Ensure FCV-2210Y, Boric Acid valve, selector is in AUTO. i f U-@ if blending directly to the VCT, then open V2512, Reactor Make mop vMve. 1il I- } ! g$ If direct path to the charging pump suction is desired the
- j , n open valve 1 <
V2525, Boron Load Control Valve. b1* 0 [3 ff {.5 9'. N 4
l
._ Pege 16(20 ~
ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-0250020 REVISION 35 lbh o . c ?g BORON CONCENTRATION CONTROL - NORMAL OPERATION
^ ' W gg
8.0 INSTRUCTIONS
(continued) h Mt 8.5 (continued) h f@ CAUTION 5 To preclude lifting the VCT relief valve while using V2525, do not allow the GE i combined PMW and boric acid flowrates to exceed the running charging
.N pump (s) capacity. ,
O k @,
\j Adjust FRC-2210X and FRC-2210Y to the desired flow rates.
i i y N.fLT]i j ls Monitor VCT level for increase. l l M 1 The addition of Boric Acid should be completed before the PMW, such that, \ j the total blend volume remaining allows for at least 30 gallons of primary ) makeup water alone, to flow through the lines and flush out any remaining j beric acid. M- ($ When the desired amount of Boric Acid has been add @ ace the i selector switch for FCV-2210Y to CLOSE.
]
s " <@l When the Boric Acid and water flow totalizers show that the proper O
' amounts have been added to the VCT, then close V2512 or V2525, which ever was used. % .a, Bwfa ~p aJ O' @Snp.A ,.u Place the runriing BAM pump switch to AUTO.
P. @ Close FCV-2161. ',U G.8. Close FCV-2210X. s R. $ Monitor for any abnormal change in temperature. Check Boronometer for undesirable change in Boron Concentration. ) M M MM b E 2- 8,E.3 f[A J
__..._ ) ST. LUCIE UNIT 1 P OPERATING PROCEDURE NO. 1-0250020, REVISION 35 : BORON CONCENTRATION CONTROL - NORMAL OPERATION l
8.0 INSTRUCTIONS
(continued) 8.5 (continued) I
- 2. Manual Dilution i blD.TJ VCT level equates to 33.8 gallons per percent of scale on LIC-2226, VCT Level.
A. Determine the desired volume of water to be added. B. Ensure the Make-up Mode Selector switch is selected to
$_ MANUAL.
c-i C. i Ensure that FRC-2210X, Make-up Water Flow, is in h MANUAL and reduce the contrcller cutput to zero (0). I D. O Ensure that FRC-2210Y, Boric Acid Flow, is in MANUAL. and reduce the controller output to zero (0). D E. Ensure that FCV-2210Y, Boric Acid Valve, selector is in CLOSE. ig F. Ensure that either the 1 A or the 1B Primary Make-up Water Pump is running. l G. Place FCV-2210X, Reactor Make-up, selector switch in
' i AUTO.
H. 11 diluting to the VCT, Ihan OPEN V2512, Reactor Make-up Water Stop Viv.
- 1. 11 diluting directly to the suction of the charging pumps, Theto OPEN V2525, Baron Load Control Valve.
A d 4 4
~! ST. LUCIE UNIT 1
- OPERATING PROCEDURE NO. 1-0250020, REVISION 35 4 1
BORON CONCENTRATION CONTROL - NORMAL opt-RATION I 8.0 INSTRUCTIONS: (continued)
- 8.5 (conti1ued)
- 2. (continued) .
1 CAUTION - i ) To preclude lifting the VCT relief valve while using V2525, do NOT allow the PMW flowrate to exceed the running charging pump flow rate. J. Adjust FRC-2210X to the desired flowrate. I N , K. i If. necessary to maintain the desired VCT level, 'Ihan ; ) , Q divert the letdown flow to the WMS by placing V2500, VCT Divert Valve, in the WMS position. ! L. Y When the desired VCT level is reached,3han: 7\ 1. ! I Return V2500, VCT Divert Valve, to the AUTO : position.
% 2.
Ensure that V2500 indicates CLOSED. Q M. When the desired amount of PMW has been added, Ihnn n place the FC ' 2210X selector switch in the CLOSE position. N. CLOSE V2512 or V2525, whichever was used. ' O.
- Ensure that FRC-2210X is in MANUAL and reduce the controller output to zero (0).
P. Monitor for unexpected results:
- 1. Abnormal change in the RCS temperature, i
4
- 2. Undesired change in the RCS boron concentration by boronmeter indication. ;
a i
l ST. LUCIE UNIT 1 ! OPERATING PROCEDURE NO. 1-0250020, REVISION 35 BORON CONCENTRATION CONTROL - NORMAL OPERATION ! 8.0 INSTRUCTIONS: (continued) 4 8.5 (continued)
- 3. Manual Boration bl9.T.Ei VCT level equates to 33.8 gallons per percent of scale on LIC-2226, VCT Level.
A. N Determine the desired volume of boric acid to be added. 9 B.
$ Ensure the Make-up Mode Selector switch is selected to MANUAL.
I C. Ensure that FRC-2210X, Make-up Water Flow, is in g MANUAL and reduce the controller output to zero (0). s O\ g D. Ensure that FRC-2210Y, Boric Acid Flow, is in MANUAL and reduce the controller output to zero (0). i E. k Ensure that FCV-2210Y, Boric Acid Valve, selector is in CLOSE. Q, F. Ensure that either the 1 A or the 18 Primary Make-up N Water Pump is running. LlDlli While it is acceptable to use either BAMT for RCS boration, it is preferable to operate the BAM Pump for the BAMT NOT designated as ' Tech Spec'. G. START either the 1 A or the 18 BAM Pump. H. Place FCV-2210Y, Boric Acid Valve, selector switch in AUTO. -
- l. OPEN FCV-2161, Boric Acid Make-up Isolation.
J. It borating directly to the VCT, ]han OPEN V2512, Reactor Make-up Water Stop Viv.
t 1- j 4 ST. LUCIE UNIT 1 i OPERATING PROCEDURE NO. 1-0250020, REVISION 35 ' g - BORON CONCENTRATION CONTROL - NORMAL OPERATION i j ' 8.0 INSTRUCTIONS: (continued) 8.5 (continued)
- 3. (continued) I 4
1 l 1 K. H borating directly to the suction of the charging pumps,
- Then OPEN V2525, Baron Load Control Valve.
j L. Adjust FRC-2210Y to the desired flowrate. i N H M. H necessary to maintain the desired VCT level, Rign divert the letdown flow to the WMS by placing V2500, i VCT Divert Valve, in the WMS position. i I N. When the desired VCT level is reached, Rign: L
- 1. Return V2500, VCT Divert Valve, to the AUTO
[ D position. I k 2. Ensure that V2500 indicates CLOSED. 4 j iQ , O. EbAn the desired amount of boric acid has been added, ( j l Elan place the FCV-2210Y selector switch in the CLOSE position. l' I ] ! P. CLOSE FCV-2161, Boric Acid Make-up Isolation. t i i 4 CAUTION To preclude lifting the VCT relief valve while using V2525, do NOT allow
- j the PMW flowrate to exceed the running charging pump flow rate.
1 i i Q. ' STOP the running BAM pump and place the selector j l switch in the AUTO position. i I-W
i 1 ST. LUC!E UNIT 1 i OPERATING PROCEDURE NO. 1-0250020, REVISION 35 i BORON CONCENTRATION CONTROL - NORMAL OPERATION i i 8.0 INSTRUCT 10NS:- i (continued) 8.5 (continued) 3 3. (continued)
- l h R.
j 11 flushing the CVCS piping following boration is desired, a .Then: i i pg 1. Place FRC-2210X, Make-up Water Flow, controller q in AUTO. i h CAUTION g To preclude lifting the VCT relief valve while using V2525, do NOT allow { the PMW flowrute to exceed tne running charging pump flow rate.
- 2. Adjust FRC-2210X to the desired flowrate to flush g
l the lines with a total of at least 30 gallons of PMW. l. D 3. j k When the desired amount of PMW has been added, Than place the FCV-2210X selector switch in the CLOSE position. I~ .
\ 4.
! Place FRC-2210X in MANUAL and reduce the 1 controller output to zero (0).- I ! S. i CLOSE V2512 or V2525, whichever was used. l l 1 T. Ensure that FRC 2210Y, Boric Acid Flow, is in MANUAL and reduce the controller output to zero (0). 4 3
- U. Monitor for unexpected results:
i { 1. Abnormal change in the RCS temperature. r.
- 2. Undesired change in the RCS boron concentration j }
i by boronmeter indication.
. _QL5-PR/P_SLd_.
Revision 67 December,1995 Page 1 of 101 PSL g T n FLORIDA POWER & LIGHT COMPANY i O NUCLEAR ENERGY DEPARTMENT L I ST. LUCIE PLANT Mioct.ount PnobuCT!oN PREPARATION, REVISION, REVIEW / APPROVAL OF PROCEDURES
1.0 APPROVAL
Reviewed by Facility Review Group 1/30,1975 Approved by J.H. Barrow (for) - Plant General Manager 2/31975 Revision 87 Reviewed by FRG 12/8 19,33_ Approved by- J. Scarola Plant General Manager 12/8 19,95.
2.0 PURPOSE
2.1 This procedu' re provides administrative guidance for the preparation, review, approval and revision of all plant procedures and letters of instruction, for use at the'St. Lucie Plant. 2.2 This procedure defines the instructions that shall be used by St. Lucie Plant personnel to assure conformance with NRC Regulatory Guides 1.33 and 1.68, NUREG-0737 and the Site Quality Manual (SOM 2.1 and 5.0). ) S_ OPS DATE l DOCT PROCEDURE DOCN QI-5-1 SYS COMP COMPLETED ITM 67 l
___~ . _ _ _ _ . _ . _ _ . . - . _ _ . _ . .
~ ~
Ql.5-PR/PSL-1 . Revision er December,1995 Page 41 of 101
5.0 INSTRUCTIONS
(continued) 5.12 (continued) 2.
. Controlled vendor technical manuals may be utilized as references to safeh l
/ or non-safety related NPWOs to provide technical guidance (e.g.,
DW Gs, specifications, torque values, dimensional information,
- vo'tage/ current values, etc.) to supplement an invoked plant ar? proved .
l procedure / guideline or the work scope / instructions without prior FRG ' Review / Plant General Manager approval. In this case, the vendor's s ! step-by-step maintenance instructions are not being used. ' ' 3. Changes to technical manuals received from the vendor or changes initiated by FPL shall be forwarded to PEG /JB for review and approval.
- 4. ;
New technical manuals received from vendors shall be numbered an ; controlled in accordance with O! 6-PR/PSL-1. ' 5. The maintenance and preventive maintenance requirements specified in ; technical manuals shall be considered when writing maintenance j procedures. Vendor recommendations for preventive maintenance l activities or frequencies contained in th6se Vendor Tech. Manuals may be deviated from, provided a technical review is performed by the respective maintenance engineering group. 6. Distribution of revisions to vendor technical manuals shall be maintaine by the information Services Supervisor or designee. 5.13 Adherence to Procedures:
- 1. 1 A strict adherence to procedural requirements - Verbatim Compliance - is the policy expected and required of all St. Lucie Plant personnel.
2. A procedure shall be performed in a step by step manner, with each step being completed prior to the performance of the next step, unless exceptions allowed by the procedure or as specified by thb procedure. , A. Procedures and Instructions of an Administrative nature (Quality Instructions, ADMs, etc.) shall not be violated, but step by step implementation is not required. By nature, these types of procedures and instructions often do not lead themselves to sequential implementation. l B. ( Procedureis and instructions that are of a technical nature shall be , !- followed sequentially except as specifically allowed by approved plant procedures.
._._QI 5-PR/PSL 1.-~ ~.T.~ _.-
Revision 6T December,1995 I 3 Page 42 of 101
' r
- 5.0 INSTRUCTIONS
- (continued) j 5.13 (continued) 2.
i 1 (continued) l B. (continued) !
- 1. Required sign-offs and data entries shall be made as each step is
- performed. )
1 [ i
- 2. If a procedure step cannot be completed as written, or if in the
! judgement of the individual performing a procedure, compistion of a specific step (s) could result in an unsafe condition (e.g., personnel injury, damage to equipment, conditions outside the limits of the procedure etc.), conduct of the procedure shall be i stopped, the systemicomponents placed in a safe condition and ! the Nuclear Plant Supervisor shall be notified.
- 3. Deviation from Procedure Valve Checklists may be made l
provided the deviation is noted in ink on the applicable valve alignment and is approved (initialed and dated) by the Nuclear j Plant Supervisor.
- 3. Personnel shall not give directions, guidance, recommendation, or clarifications which conflict with approved procedures. !
- 4. Adherence to procedures shall be accomplished by use of one of the following methods
i ! A.
' Method 1 - Procedure Present Durino Performance of Activity: The p
types of procedures that shall be present and referred to directly are: i
- 1. Those procedures developed for extensive or complex jobs where reliance on memory cannot be trusted.
1
- 2. Tasks which are infrequently performed.
4
- 3. Tasks which must be performed in a specified sequence and/or 4- which verification is documented by initial or signature.
i 4
. a.. s . . . . . . . . s-.- n-.~n , s. ~. s-..+..,-.a.--- . . - . . ..u-.u.-- - -.... .....,u . - - . , . . . a.,a.. -n.,a,- -a.. u. n.n,,
. . .QL5-PR/PStd Revision 67 Y
December,1995 Page 43 of 101
5.0 INSTRUCTIONS
(continued) j 5.13 (continued)- , B. Method 2 - M,emorization: Method by which the procedural steps for j the required actions are committed to memory. This method does not ] . permit any deviation from the Procedural Adherence Policy. s ' 1. Procedures for which actions should be committed to memory are immediate Actions in Emergency Operating Procedures and Off l Normal Operating Procedures. i
- 2. Procedures for which actions may be committed to memory are I
{ routine procedural actions that are frequently repeated and may not require the procedure to be present during performance of the i activity. However, copies of procedures shall be available to the user at his/her work location for reference during performance of the task, if necessary. 1 j 5. Procedural adherence may be accomplished by use of a Temporary 1 Change,if necessary. 4 , 6. When used in a procedure the word "shall" is used to denote a i requirement, the word "should" to denote a recommendation and the word !
"may" to denote permission, neither a requirement nor a recommendation. 1
[,
- 7. Independent Verification:
4
- A. Independent Verification has been defined in ADM-17.06, j
" Independent Verification." Definitions of Independent Verification ;
should not be added to procedures as they may conflict with the ' j guidance outlined in ADM-17.06. r.,~e-m -- m -~- .-
._ Pcge_1 of_174 _1 FLORIDA POWER & LIGHT COMPANY i 4
ST. LUCIE PLANT ! ADMINISTRATIVE PROCEDURE NO. 0010120 ' REVISION 79 r pst. _ l E
- a II n f
1.0 TITLE
E E $ o 1 J CONDUCT OF OPERATIONS ' O l-L
; PROCEDURE ,
2.0 REVIEW AND APPROVAL: - 1 4 Reviewed by Plant Nuclear Safety Committee 1/17 1975'
- Approved by J. H. Barrow (for) Plant General Manager 1/22 1975 Revision 79 Reviewed by Facility Review Group 12/21 19.25_.
Approved by J. Scarola Plant General Manager 12/21 1995
3.0 SCOPE
3.1 Purpose
I This procedure defines the responsibilities and conduct of the Operations Department during the performance and documentation of all departmental activities. This procedure provides instruction to ensure that plant operations are conoucted in an effective, consistent, professional and businesslike manner as per the operating license, plant procedures and applicable regulatory requirements. l l ) ~ This procedure applies to all persons in the Operations Department. It j identifies operational requirements and management policies necessary to l ensure the daily conduct of plant operations is consistent with good I
- operational and engineering practices. '
S_ OPS DATE ' DOCT PROCEDURE DOCN 0010120 SYS COMP COMPLETED ITM 79
~
Page.41 sf 174. ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 79 CONDUCT OF OPERATIONS APPENDIX D CREW RELIEF / SHIFT TURNOVER (Page 5 of 5)
- 1. (continued)
D. InstnJction for an interim or Short Term Relief / Shift Tumover.
- 1. If a specific watchstander requires a short term relief for a period of less -
than 2 hours. then the following instructions provide the minimum requirements for shift relief:
- a. General watchstation status,
- b. Off-norrnal conditions. !
l
- c. Tosts in progress. I i
- 2. The applicable unit ANPS shall be notified immediately after the shift i
, tumover nas been completed. { l l 3. If an individual is expected to be aosent for period of greater than 2 hours, then an Individual Relief / Split Shift Tumover shall be performed. ~
\
i I d 3 l
~
Page.42~of 174' ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 79 J CONDUCT OF OPERATIONS ' APPENDIX E NOTIFICATION OF OPERATIONS SUPERVISOR /FPL MANAGEMENT (Page 1 of 3)
- 1. The Nuclear Plant Supenrisor is responsible for notifying higher station authorities and appropriate station personnel. Advance notification should be made when possible. The following situations require prompt, verbal notifications:
i Notify the Operations Supervisor for the following situations: " A. Any event that would cause entry into an Emergency Operating Procedure (EOP). B. Any event requiring phone call notification to the NRC. C. Any event that will generate an LER. D. Inadvertent radioactive liquid or gaseous release. E. Major equipment failure or malfunctions. l F. Unexplained or unplanned reactivity changes. G. Forced power reduction. H. Major personnel injury or radiation overexposure. I, Any LCO that would require unit shutdown within the next 24 hours. J. Any operational event that generates an in House Event (IHE) Report AND causes heightened awareness to FPL sources offsite. K. Any release that is or is potentially, damaging to the environment. L. Load restrictions or inability to meet load dispatcher requirements. This includes, but is NOT limited to the following:
- 1. A planned power escalation is unexpectedly halted for any reason and can not be resumed within one hour.
- 2. If at a power level less than 100 percent, any unexpected condition that would prevent a future power escalation and can not be resolved within two hours.
- 3. If at a power level less than 100 percent and the plant is unable to support an unexpected request for more power from the load dispatcher.
- - . - . . ~ . . . - . . . . - . . - - - . - . . - - - . . . -
Pcge-48.of 1.74 - ST. LUCIE PLANT ! ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 !~ CONDUCT OF OPERATIONS j APPENDIX F LOG KEEPING ! l (Page 2 of 9) j 2. Chronolooical Loos. i i ! A. ' Log books and/or computerized logs shall be maintained at the RCO, . NO/SNPO, NTO/NPO and ANPO normal stations. Entries are to be in concise j and complete enough to reconstruct the events of the shift. Particular ~ l attention should be made to the entries pertaining to any. abnormal condition that occurs. Times for each entry shall be as near correct as possible 'using military time. The entries are to be made in chronological order.
- 1. Evolutions, manipulations and operations that are performed, observed and monitored by operators NOT actively assuming the responsibilities of a particular watch station shall be recorded in the applicable watch station chronological log and initialed by that operator. The operator should notify the responsible watchstander of the log entry. -
- 2. When it is necessary to insert additional information after the fact, Then the entry shall be recorded with the actual time of occurrence, the words Late Entry in parenthesis, and the information to be logged.
Example: 1234 Started the_1 A EDG for surveillance run 0827 (Late Entry) Filled the 1 A2 SIT with the 1B HPSI ! Pump in accordance with OP 1-0410021 l 1345 Secured the 1 A EDG, Surveillance run SAT. :
- 3. When it is necessary to correct information recorded in error, then the entry shall be recorded with the actual time of occurrence, the words
" Corrected Entry" in parenthesis, and the information to be logged.
Example: 1234 Started the 1B EDG for surveillance run 1345 Secured the 1 A EDG, Surveillance run SAT. 1234 (Corrected Entry) Started the 1 A EDG for surveillance run
- 4. Entries in the RCO log should include, but are NOT to be limited to, the following:
- a. Conditions at the beginning of each watch.
PCge 4Tof 174 . . . _ ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 CONDUCT OF OPERATIONS APPENDIX F LOG KEEPING (Page 3 of 9)
- 2. Chronolooical Loos: (continued) 1 A. (continued)
- 4. (continued) ~
l b. Significant changes in plant conditions. Examples: 1. Mode changes.
- 2. Loao changes.
- 3. Reactivity changes.
- 4. Startups and Shutdown.
- 5. Time of Reactor enticality,
- c. Any new condition that would limit unit generation.
Examples: 1. Concenser back pressure at administrative limits.
- 2. Chemistry parameters limiting operation.
- d. Special tests, including periodic and surveillance testing, for major equipment.
Examples: 1. Start and stop times for periodic or surveillance tests and outcome (SAT or UNSAT), for major equipment.
- 2. Post maintenance. testing and outcome, for major equipment.
- e. , Control problems associated with major equipment or systems.
Examples: 1. Changes in plant work arounds.
i j: - PIge.70 of 174' i 1 ST. LUCIE PLANT i- ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 i CONDUCT OF OPERABONS i $: APPENDIX M [ PROCEDURAL COMPUANCE AND IMPS suENTATION I: (Page 1 of 6)
- 1. Controlled procedures are available in both Control Rooms and shall be t
implemented and complied with in accordance with the instructions provided in i O! 5-PR/PSL-1, " Preparation, Revision, Review / Approval of Procedures." l b . 2. In the etont of an emergency where procedural guidance does NOT exist or in ' ! which a specific emergency is NOT addressed by an approved procedure, then 3 Operations personnel shall take action to protect the health and safety of the public, minimize personnel injury, and damage to the facility. t
- 3. Numerous tasks performed by the operators are repetitive and routine in nature.
i These tasks come under the guidance of the memorization method of adherence to i procedures in accordance with 015 PR/PSL-1, " Preparation, Revision, Review / Approval of Procedures," and may be performed from memory. These tasks, which are listed in the following sections, are considered to be skill of the i trade for qualified operators. Each listed task shall have one or more of the below j justification reasons: a (A) Task is routine and not complex - satisfactory completion assured by j routine training and observation. v (B) Task is routine and has a low level of complexity - satisfactory completion assured by completion of verification checklist and independent verification. 1-1 } (C) Posted instructions in place as reference. ) 2 j (D) Satisfactory completion assured by multiple levels of review and/or i feedback from system. e ! A. General Control Tasks
- 1. Racking IN and OUT of 6.9 KV,4.16 KV, and 480V breakers. (B) o
- 2. Tuming ON and OFF 480V MCC breakers. (D) i e 3. Writing clearances and NPWOs. (A,D)
- 4. Changing chart paper. (A,D)
~
- 5. Placing controllers in MANUAL or AUTO. (A,D)
] 1 i __
4 i Page.71 of174 -- i i. ST. LUCIE PLANT ! ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 79 CONDUCT OF OPERATIONS l e i APPENDIX M PROCEDURAL COMPLIANCE AND IMPLEMENTATION (Page 2 of 6)
- 1. (continued)
{ [ B. Reactor Control Operator
- 1. Divert Letdown to Control VCT level. (A,D) ~
- 2. Check Sheet 1 of AP 1-0010125. (A,B,D)
- 3. Refueling Operations - movement of machine, etc. (A,D)
- 4. Adjusting Main Generator loading, including Megavars and Megawatts
. (manipulation of DEH controls). (D)
- 5. Swapping Auxiliary and Start-up Transformers. (D) i
- 6. Adjusting CEA position (eg. ASI control). (D) 1 i
- 7. Manipulation of control valves (ADVs, FCVs) to control Heatup and j Cooldown rates. (D)
- 8. Pumping down Reactor Drain Tank. (A,D) I i
- 9. Placing CST on recire. (A,D) i C. Senior Nuclear Plant Operator 1.
Generic Rounds Sheets. (A)
- 2. Swapping H'JTs. (A,D)
- 3. Blowing down BAMT level transmitters. (C)
- 4. Operator Readings and AP 0010125 checks. (A,B,D)
- 5. Recirculating of HUTS, WMTs, and AWSTs. (A,D)
- 6. Backwashing ICW/CCW strainers. (C)
QI 5-PR/PSL-1 ..-. . . . .
. . p- g 7-.. .
December,1995 Page 92 of 101 i FIGURE 4 i TEMPORARY CHANGE REQUEST , i (Page 1 of 3) A Reference information: (Originator to complete) . St. Lucie Unit # com-M TC # o O/'/ I I Procedure
Title:
roso ve- or opre/n os s 47 oo/0 /2 o Rev. ~)4 ~ Proceoure Number: Reason for change: ,ac aron d m a sa c ry ss e o,aren se s
=rss $ TC $JPttCEOff Tc_ 0 -9L - O f I l Originator: d*lAf d Phone: ~704 / Date: / / AS/ 96 B Proceourni Controts: (Originator to complete)
Yes No O 5 is the intent of the procedure aitcred? (Tech. Spec. 6.8.3.A) If yes, a TC is NOT applicable. A PCR is required, j I O E is this Temporary Change for a one time use? If yes, this TC can be executed pm time only, if no, this TC may be used up to 90 days, and the originator of the TC shall 1 submit a procedure cnange request incorporating this TC at the same time the TC is I approved.
, Department Head or Designee K / /29 / /0 #
j O E is this T.C. for a o.l.? If yes, the cuality Manager or designee and the Dept. Head or designee who is jurisdictionally responsible for the 0.1. shall sign. ; Quality Manager or Designee / / Department Head or Designee / / C Temocrary Chance Contents: (Originator to complete) i Does this Change: l Yes No O 9 Incorporate complex or extensive changes? If Yes, Subcommrttee required. l Subcommrttee i Initials O 5 Modify instrument setpoints? i O E Delete an indepenoent venfication? ; O 3 Alter a QC holdpoint? O O Modify a procedural step which afters a regulatory requirement as identified in the l l proceoure? i l O S Alter the first execution of a procedure? (Preop, LOI) O 3 Addition of any chemicals? l NOTE < l if any of the above entena are marked yes, pnor FRG review is required. ! l I i l /R67 i 1
i QI 5-PR/PSLs1 . Revision 67 ~ - t i December,1995 Page 93 of 101 ] FIGURE 4 i TEMPORARY CHANGE REQUEST j (Page 2 of 3) i TC # 0 -96 O/Y D to CFR 50.st Seroeneng Yes N 4 1
- 1. Dm me change represent a criange to me tecdity as assenbod m the SAR7 /o
! 2. Does me change represent a enange to procedures as casenbod in the SAR7 .
- 3. Is me enange "w='M vnth a test or expenment not desenoed m me SAR? /
3 . 4. Could me enange affect nuclear satefy e a way not promously evaluateo en
- 1' tneSAR7 7 ,
f S. Does tne change reouire a enange to tne Techndal SpeciAcanons? / E
- If the answer to & the above 10 CFR 50.59 screening questions are no. (Questions 1 1 5), then a safety evaluation is not requirec.
STA rewsw asignaturen YN/[% Date I 'l_3 / 1 l E Does inis enange: (NPS to comsfete") Yes No l 1. ' Compromes the seoaranon of redundant trams of souspment?
- 2. PotensaHy isolate pressure reliefs? */
l 3. ' Detent automane signals? / { 4. Defeat mecnancel or electncal mterlocks? /
- 5. Aner tne completon 'of an evoluton oue to an operator work around V l if yes to No. 5. auinonzanon from tne Plant General Manager or Site Vice Presioent snad be obtained.
I i { Ogte f i Yes No O I Pnor FRG review roowed? M
- if any of the above enteria are marked yes, ciscuss possible alternatives with the
- enginator. - g-/
} NPS Signature #f///T/ Date ' ' 2 'f / N F FRG Aewow- ! Plant General Manager Approval Date ' ' FRG Numoer - This change snat be rewswed (if pnor FRG rewow a not g recured) by the Faciinty Rewow Group and approved by the Plant General Manager wnhin 14 asys of the auenonzaton cate. (Tech. Spec. 6.8.3.C) RE.lECTED by FRG/ Plant General Manager Date ' '_ 4 i Reason. i i Retum to Ongmaior i
! 11 ts the responsioility of tne anginator of the retected temporary enange to cancel the enange m the approonste Control l Room, costroy all Se6d cooes and halt at subseouent evoluuons useg t'us temporary enange i
d I
._--__m.._r ,
~
QI p 5-PR/PSL-1 -.. .- . December,1995
- Page 94 of 101
- FIGURE 4 3
TEMPORARY CHANGE REQUEST (Page 3 of 3) i G Tc s 0 - %- *4 4 Aporovat: (This change shall have pnor approval by a NPS and one member of the plant management staff.) (Tech. Spec. 6.8.3.8) ! Plant Management Staff Si tur - OPST7[l- Date / /21.,/ 96 f 3 NPS Signature N Authorizaton Date / /t f if 6 l H Oancellaton Authonzation (NPS/ANPS) Date / / s Reason: ,_ _ i i l i i ) i i i 1 i J l i 4 1 a ( 1 1 1
< , - ~'
i .
- P;ge-30 cf -174- -
i l ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 CONDUCT OF OPERATIONS APPENDIX B SHIFT OPERATIONS POLICIES ! (Page 5 of 8) i 4. (continued) l l A. (continued)
- 4. P - Prove
- a. Prove to yourself that the actions that were just performed produced
- the desired results.
! I l b. Observe and verify the following: l 4 l 4
,E 1. The task was performed correctly. .)
i
?-
1 g'y .
- 2. The actual response was the expected response.
- 3. The component / system is in the proper i:onfiguration to support i
, cfs Q the intended operation.
a pk 4 4. The proper component was operated. j ,4p m
- 5. Mi uB ivi-Jpulation _
%x
^
\ -
i ' s 4 A. Only licensed operators areJamrut4Wiii'anipulate the controls that directly affect the rgeaower level of a r5 actor-excegfor training purposes. A . t Fy manipulate controls only under direct visual supervisigrLof a licensed operator. N 4 6. Unit Reliability A. The NPS/ANPS should make every effort to prevent putting the plant in a situation where a single failure would jeopardize plant safety or availability. Systems listed under AP 0010142, " Unit Reliability - Manipulation of Sensitive ! Systems" warrant particular attention. Maintenance or testing should not be allowed on an in service train or channel with the opposite train out-of service or another channel in Trip, except for Tech. Spec. required surveillances or to prevent a plant shutdown. 7 7
t t TC 0 - %, - 014 l 4 3 APPENDIX B , 1- ' SHIFT OPERATIONS POLICIES ! i e l' 5. Reactivity Manipulations i A. Reactivity manipulations in the course of normal plant operations is defined as ' i the insertion of positive and negative reactivity due to manipulation of the j following: 1
- 1. CEA insertion and withdrawal. l n i I
l 2. Addition of water and/or boric acid to the VCT or Charging Pumps' j j suction.
- 3. Turbine /Generatorload changes.
l
- 4. Placing a purification lon Exchanger in service, (any time V2520, "lon Exchanger Bypass Valve," position is changed from bypassing the ion
[ exchanger (s) to directing flow through the ion exchanger (s)). i !' B. All reactivity manipulations in the course of nonnal plant operations, both positive and negative, shall have prior approval from the SRO fulfilling the role of the Control Room Command function, except as provided for in step 5.D. i. 4 C. When reactivity manipulations are being performed, both positive and ! negative, the SRO fulfilling the role of the Control Room Command function i shall directly supervise the manipulation and additionally assume the role of a
- reactivity manager, except as provided for in step 5.D.
< { ! l i D. In the event of off-normal and emergency conditions, Reactor Control ! Operators are authorized to perform reactivity manipulations without the ' j-presence of and approval of an SRO, if in his/her judgement immediate ! intervention is required to protect the health and safety of the public and/or challenging of plant safety functions. The SRO fulfilling the role of the Control i Room Command function shall be notified of the manipulation as soon as i' possible. 1 i E. Crew Relief / Shift Turnover shall NOT take place for Reactor Control , ) Operators or the Assistant Nuclear Plant Supervisor while reactivity
! manipulations are in progress.
a i
. 1 i _. .. _
'll, - OiA
~
l TC l I APPENDIX B j l SHIFT OPERATIONS POLICIES
- 5. (Continued) 4 F. Reactivity manipulations shall be performed only by those individuals possessing an active license applicable to the unit on which the manipulation i
is being performed. The only exceptions are persons reactivating a license or
- in a bonafide training role in pursuit of obtaining a license; they may perform reactivity manipulations under direct visual supervision of a licensed operator with an active license.
l l 4 ) i e i I
. ~
P;ge-40 of 474 ^ ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 79 . I- CONDUCT OF OPERATIONS APPENDlX D CREW RELIEF / SHIFT TURNOVER l (Page 4 of 5) i
- 1. (continued) l .
! C. Instructions for an Individual Relief / Split Shift Tumover L ;
- 1. If a specific watchstation shift is being split by two individual watchstanders, then the following instructions provide the minimum requirements for shift relief:
l a. The off-going watchstander shall review applicable plant log sheets to determine the existence of any off normal condition or trends. j* l' s*, %* ,
- , Ji l' b. The off-going watchstander shall complete the applicable Tumover Check Sheet (Data Sheet 1) for their watchstation. l
!. . 1 4 .' @< c. The off going watchstander shall verbally transmit and explain the
!~ information as recorded on their applicable Tumover Check Sheet
- # (Data Sheet 1) to the on-coming watchstander.
. 6 > g f. The on-coming watchstander shall review the following and l k, 3 acknowledge that review by initialing Check Sheet 1 of c AP 1(2)-0010125, " Schedule of Periodic Test, Checks, and l l
- e.<
g,y[' , Calibrations.'
- 1. Applicable Watchstation Chronological Log.
l
- 2. Applicable Watchstation Operator Log Readings. !
- 3. Night Order Book.
- 4. NPWO, ANPS, and NWE shall review equipment out-of-service l- 10 9 .
3 a f. The applicab!e unit ANPS shall be notified immediately after the shift J tumover has been completed. e a'
. --. . . . . . - - , ._ .= -.- . . .-
1 i
~Il- 0 - 9(, - 014 '
f APPENDIX D
- CREW REllEFISHIFT TURNOVER !
- .1.
C. 1. i
- d. On-coming and off-going control room watchstanders shall conduct a face-to-face complete walkdown of the RTGBs and control panels. I i
4
- e. The on-coming watchstander shall make a chronological log entry ;
indicating he/she has assumed the responsibilities of the watchstation. l i 0 4 i i
p ,g , ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 CONDUCT OF OPERATIONS l APPENDIX D CREW RELIEF / SHIFT TURNOVER (Page 5 of 5)
- 1. (continued)
D. Instruction for an interim or Short Term Relief / Shift Tumover.
- 1. If a specific watchstander requires a short term relief for a period of less '
- . than 2 hours, then the following instructions provide the minimum requirements for shift relief:
# 0
- a. General watchstation status.
. -M
~
- b. Off-normal conditions.
f's c. Tests in progress. *
'e
& y ,3 y 2. The applicable unit ANPS shall be notified immediately after the shift
~
tumover has been completed, 9a( j 3. If an individual is expected to be absent for period of greater than 2 hours, then an Individual Relief / Split-Shift Tumover shall be performed.
.8 E
i l
~~
l TC. o - 9 (, - 014 l APPENDIX D CREW RELIEF / SHIFT TURNOVER 1. D. ! 1 1.
- d. Control room watchstanders with the responsibility of the Operator at the Controls or the Control Room Command function shall conduct a face-to-face complete walkdown of the RTGBs and control panels with the l individual assuming their responsibility.
l l i
_ ~. _ . _ . _._ _ _ _ - . a ~ Uodated_ner Amendment 134 dated 3/15/95 DPR-67 l Page 1 FLORIDA POWER & LIGHT COMPANY _. l P5t. DOCKET NO. 50-335 '
- ST. LUCIE PLANT UNIT NO. 1 1 FACILITY OPERATING LICENSE l WE PRODUCnON '
- 1. The Nuclear Regulatory Commission (the Commission) having found that:
A. The application for license filed by Florida Power & l Light Company (the licensee) complies with the standards j i and requirements.of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions's rules and regulations set forth in 10 CFR Chapter 1 and all ! required notifications to other agencies or bodies have ! j been duly made; a ' B. Construction of the St. Lucie Plant, Unit No. 1 j (f acility) has been substantially completed in conformity- ; with Construction Permit No. CPPR-74 and the application, as amended, the provisions of the Act and the rules and regulations of the Commission; C. The facility will operate in conformity with the
- application, as amended, the provisions of the Act, and
- the rules and regulations of the Commission; D. There is reasonable assurance
- (i) that the activities au'thorized by this operating license can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in i
compliance with .the rules and regulations of the
- Commission; E. The licensee is technically and financially qualified to engage in the activities authorized by this operating license in accordance with the rules and regulations of the Commission; F. The licensee has satisfied the applicable provisions of
, 10 CFR Part 140, " Financial Protection Requirements and Indemnity Agreements," of the Commission's regulations; G. The issuance of this operating license will not be inimical to the common defense and security or to the health and safety of the public; 4 4
4 i , Undated Der Amendment 134 dated 3/15/95 DPR-67
- 'Page 3 I
(3) Pursuant to the Act and 10 CFR Parts 30, 40, and ! 70, to receive, possess and - use at. any time . byproduct, source and special nuclear materd ,.1 as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission l detectors in amounts as required; (4) Pursuant'to the Act, and 10 CFR Parts 30, 40, and , 70, to receive, possess and use in amounts as i required any - byproduct source or special nuclear-
- material without restriction to chemical or
', physical form, for sample analysis or instrument t calibration or associated with radioactive apparatus or components; i (5) Pursuant to the Act and_10 CFR Parts 30 and 70, to
- possess, but not separate, such byproduct and-
; special nuclear materials as may be produced by the j operation of the facility.
! C. This license shall be deemed to contain and is subject to - the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Sections 30.34 l of Part 30, Section 40.41 of Part 40, Section 50.54 and ! 50.59 of Part 50, and Section 70.32 of Part 70; and is subject to all applicable provisions of the Act and to
- the rules, regulations, and orders of the Commission now j or hereafter in effect; and is subject to the additional
- conditions specified or incorporated below; 4
(1) Maximum Power Level The licensee is authorized to operate the facility at steady state reactor core power levels not in f) excess of 2700 megawatts (thermal), provided that ' 4 the construction items, preoperational tests, j j startup tests, and other items identified in F.nclosure 1 to this license have been completed as hl i specified in Enclosure 1. Enclosure 1 is an j integral . part of, and is hereby incorporated in
- this license.
(2) Tm Dnical snacifications i The Technical Specifications contained in
- Appendices A and B, as revised through Amendment
; No. 134 are hereby incorporated in the license. The
- licensee shall operate the facility in accordance 1
with the Technical Specifications. I 1 i d i
l-OEFINITIONS k RATED THERMAL POWER
- 1.25 !
1 RATED the reactor coolant THERMAL of 2700 POWER MWt. shall be a total reactor core heat transfer cate )
' REACTOR TRIP SYSTEM RESPONSE TIME 1.26 The REACTOR TRIP ' SYSTEM RESPONSE TIME shall be the time interval f when the monitored parameter exceeds its trip setpoint at the channel sensor until electrical power is interrupted to the CEA drive mechanism.
[
- REPORTABLE EVENT
~, 1.27 A REPORTABLE EVENT shall be any of those conditions specified in Section 50.73 to 10 CFR Part 50. ! I
\
SHIELD BUILDING INTEGRITY 1.28 SHIELD BUILDING INTEGRITY shall exist when: 1
- a. Each door is closed except when the access opening is being used for normal transit entry and exit;
- b. The shield building ventilation system is in compliance with 8
Specification 3.6.6.1, and !
- c. The sealing' mechanism associated with each penetration (e.g.,
j welds, bellows or 0-rings) is OPERABLE. J SHUTDOWN MARGIN j 1.29 SHUTDOWN MARGIN shall be the instantaneous amount of reactivity by which the reactor is suberitical or would be suberitical from its present condition ! assuming all full-length control element assemblies (shutdown and regulating) i are fully inserted except for the single assembly of highest reactivity worth I which is assumed to be fully withdrawn. . 8 i SITE BOUNDARY 1.30 site Boundary means that line beyond which the land or property licensee. is not owned, leased, or otherwise controlled by the-
- SOURCE CHECK 1.31 A SOURCE CHECK shall be the qualitative assessment of channel response when the channel sensor is exposed to a radicactivo source.
4 4 J S'
'* ?"" ' '-' ^-"'"" "" " " " " #' ' ' '
.. . - - .-.-.- ..... .~.- - -. ~ -.-....-. - ._ ... _.-.-..-. . - - -... - .
g - . . . . .. . j DEFINITIONS 1 1
- STAGGERED TEST BASIS i
l- 1.32 A STAGGERED TEIT BASIS shall consist of: i a. A test stdindule for n systems, subsystems, trains or other l j designated components obtained by dividing the specified 1 i test interval into n equal subintervals, and j b. The testing of one system, subsystem, train or other designated component y the beginning 'of each subinterval. i - THERMAL POWER t ! 1.33 THERMAL POWER stall be the total reactor core heat transfer rate to
- i. the reactor coolant. -
l . UNIDENTIFIED LEAKAGE l :t
- i. 1.34 UNIDENTIFIED LEMRGE shall be all leakage which is not IDENTIFIED l LEAKAGE or CONTROLLED AIAKAGE.
UNRESTRICTED AREA i 1.35 Unrestrictas area means an area , access to which is } neither limitad nur controlled by the licensee. I - l-i . ! UNRODDED INTEGRATED M AL PEAKING FACTOR - F l P $ 1.36 The UNRODDED IMERATED RADIAL PEAKING FACTOR is.the ratio of the peak j pin power to the avetage pin power in an unrodded core, excluding tilt.
~
I i s-1 i i i i i l ST. LUCIE - UNIT 1 1-7 Amendment No. 50,50, 100. 125 i I
.~ ._ - _ . - = . - . - . - . - - . . . . . - . . . .. . _ _.- - - _ - . - .
.'#[ 's d W.
- . , . . . ~ . - . . . . . . . .
- m.: ~\
/*~*.* Y8l-5 e .i UNITED STATES NUCLEAR REGULATORY COMMISSION I
'\ * , wAswmcTow,o.c. seses ;
August 28, 1980 l
; \
. i NOTE TO: R. Tedesco
- l T. Novak G. Lainas I agree with E. Jordan's memo in that further debate en this issue is probably not warranted at this time. Please ensure that your staff
- is aware of this interpretation and that this
- 2 will be the NRC position on this matter at l
this time. . ( 1 ) 1
- i Oarrell G. Etsenhut
~
Enclosure i cc: E. Jorcan [ l J. Scinto I i 1 } d
- --- '~
d ] O (; 1 4 0__l_ 5 3 D J h k - . 10*d 684 STEER 0PT oi Wd Wd90:0T P66T-4T-0T
L. , _ ..
. . . - ~ . -
' #[y asc..,Ie,,
~ - - '
UNITED sTATit l .
,, P p NUCLEAR REGULATORY COMMIS$10N
} [ jj m e m otow.o.s.nosse r g, 44.... gj . l
- AUG 2 21!80 ssINS #0800 s
i . i i HEMORANDUM FOR: E. J. Brunner, Chief, RO&NSB, RI l R. C. Lettis, Acting Chief, RO&NSB, RII ! R. F. Heishman, Chief, RO&NSB, RIII G. L. Madsen, Chief, RO&NSB, RIV l~ ' J. L. Crews , Chief, RO&NSB, RV , FROM: E. L. Jordan Assistant Dire:ter for Technical Programs L Division of Reactor Operations Inspection, IE i-
SUBJECT:
DISCUSSIch 0F " LICENSED POWER LEVEL" (AITS F14580H2) r Oating back at least to 1974, there have been many lengthy " discussions" regarding the exact meaning of " full, steacy-state licensed power level" (and similarly worded power limits). We do not believe the real safety benefits i that might be cerived from an NRC wide agreement would.be worth the further l expenditure of manpower in meetings, etc. that would be required to achieve a i consensus, i Ve de reali:e that some c:mmon uniform basis for enforcing maximum licensed ! p:wer is needed by I&E inspecters. Therefore, until and unless an NRC-wide position is put feward and agreec u:en (and as stated, !&E does not propose j to initiate proceedings to that and), I&E will use the following guidance. 1 l The average power level over any eignt hour shift should not exceed the " full s staacy-state licensed power level" (and similarly worded terms). The exact
- eignt neur ;arieds cefined as " shifts" are up to the plant, but should not be varied fic: cay t, day (the easiaz dafini . ion is a normal snif t manned by a
- particular " crew"). It is permissible to briefly exceed the " full, stency-state licensed power level" by as muen as 2% for as long as 15 minutes. In no
- case should 102". power te exceseec, cut lesser power " excursions" for longer
- periods should be allowed, with the above as guidance (i.e. ,1% excess for 30
=inutes, 1/2% for one hour, etc., should be allowed). There are no limits on i the numser of times these " excursions" may occur, or the time interval that
! must separate such " excursions " w. cept note that tne above requirement
- regarcing tne eight hour averags power will prevent abuse of this allowance.
a 1 k CONTACT: H. W. Woods, IE , 49-28180 M i %%lg% -
ce a wioi - 2- AUS 02 mag 4 4 . i The above is considered to be within the licensing easis and, therefore, ~ acceptadie to us, and it is also fair to the utilities and their ratepayers. i
. .. J rean, Assistant Director for Te ical Programs Division of Reac*cr Operations Inspection j Office of Inspection and Enforcement
- cc: R. C. DeYoung, IE 4
- s. J. Bryan, IE 2
f.Eisennut,HRR
- 0. Ross, NRR ,
i G I 4 ' i e i 4 i a G 4
. . _ _ _._ _._. _ ._ _ _ _ _._.____.______.____......_._m_. l i g, W 4 [yp n-4_3Q-- ..
\
- 1 I
15.2.4 i CHl!MICAL AND VOLLHE CONTROL SYSTDi MALFUNCTION - BORON DILUTIO EVENT ' I 15.2.4.1 Identification of Causes - ] The chemical and volume control system (CVCS) described in Section 9 3.4 i regulates both the chemistry and the quantity of coolant in the reactor coolant system. Changing the boron concentration in the reactor coolant ) - system is a part of normal plant operation, compensating for long-term
~ reactivity effects, such as fuel burnup, xenon buildup and decay 'and plant
!' startup 'and cooldown. For refueling operations, borated water is supplied i-l- from the refueling water tank, which assures adequate shutdown margin. An j inadvertent boron dilution in any operational mode adds positive reactivity, produces power and possibly temperature increases, and, in Modes 1 and 2 (startup and power operations) can cause an approach to both the DNBR and CTM i limits. i Boron dilution is conducted under strict administrative procedures which { specify permissible limits on the rate and magnitude of any required change in ] boron concentration. Baron concentration in the reactor coolant system can be decreased either by controlled addition of unborated makeup water with a corresponding removal of recetor coolant (feed and bleed) or by using the deborating ion exchanger. The deborating ion exchanger is normally used for { boron removal when the boron concentration is low ((ppa) and the l feed-and-bleeda ethod becomes inefficient. A boronometer is located in a line upstream of the deborating and purification ion exchangers in the CVCS. This , instrument provides a continuous measure of boron concentration and high-low ' boron concentration alarms. During normal operation, concentrated boric acid solution is mixed with fi :1 domineralized makeup water to the concentration required for proper plant operation and is automatically introduced into the volume control tank in - .' response to a low water level signal from the volume control. To effect boron I dilution, the makeup controller mode selector switch must. be set to " Dilute" [ i and the domineralized water batch qu.ntity selector set to the desired quantity. When the specific amount has been injected the demineralizer water (( ; control valve is shut automatically. i; Dilution' of the reactor coolant can be terminated by isolation of the makeup water system, by stopping either the makeup water pumps or the charging pumps, or by closing the charging isolation valves. A charging pump must be running l in addition to a makeup water pump for boron dilution to take place. '
. The CVCS is equipped with the following indications and alarm functions, which will inform the reactor operator when a change in boron concentration in the reactor coolant system may be occurring: ,
a) Boronometer high and low alarms and concentration indicction b) Volume control tank level indication and high and low alarms 15.2.4-1
- -- - - - _ . - - - - - - . - -_-. - =- .--.=. - - .. - -.
~
j ._ _.~., . ..
~
q' c) Makeup flow indication and alams i j d) Volume control- tank isolation. ,, 4 Changes in boron concentration while the reactor is on automatic control at ! full power are compensated for by repositioning the CEA's. hwever, to assist l , the reactor ogracer in maintaining an adequat,e shutdown margin, CEA insertton j below a position that would provide a minimum of one percent shutdown margin' {_ (assuming one stuck CEA) is accompanied by control room alams. Because of the procedures involved and the numerous alarms and indications available to j the operator, the probability of a austained or erroneous dilution is very low.
- 1 l 15.2.4.2 Analysis of Effects and Consequences 15.2.4.2.1 Method of Analysis
! . The time required to achieve criticality from a suberitical condition due to 4 boron dilution is based on the initial and critical boron concentrations, the , boron reactivity vorth, and the rate of dilution. Reactivity increase rated due to boron dilution are based on the boron worth and the dilution rate. . ! Cases have been analyzed f or all six operational modes, i.e. , power operation, j startup, hot standby, hot shutdown, cold shutdown, and refueling.* In each l case, it is assumed that the boron dilution results from pumping unborated i domineralized water into the reactor coolant system at the maximum possible ! rate of 132 spa (3 x 44 gpm per charging pump) and that the boron ! concentrations are uniform at all times. l The boren dilution rate is calculated by CESEC f or all cases except dilution i during refueling. CESEC described in Section 15.1.4-1 divides the reactor
- coolant system into 15 control volumes with the continuity equation beine+ # .
i satisfied by all nodes. The charging rate of non-borated water and the bTadiD 4 g content of the system are inputs to CESEC. The maximum dilution rate .
" I8j/
l (10.5 pps/ minute) occurs at the initiation of the transient. For dilution i during refueling the reactor coolant system is assumed to be one control . , . { volume with the boron concentration calculated by: the time rate of chansa_of. i boron equals, flow in times the boron concentration ininus flow out times borod j concentration. The uniformity of the boron concentration can be assured for the different
- modes of operation as follows
i l a) During refueling l- Prior to cooldown, the reactor coolant system boron concentracion is 2 increased to a minimum of 1720 ppa. The boron is mixed by the reactor
- coolant system pumps. Because the boron is chemically dissolved in the i reactor coolant , it will not precipitat e . The only possible means of obtaining a nonuniform solution is by the addition of demineralized water via the charging pumps. hwever, because the maximum water i
- An additional boron dilution event would be via the Iodine Removal System 4
(NaOH spray additive) . This event is not governing, however. j See Reference 42. j 15.2.4-2 4
, a , --
67 y e,/*
/rt f / f } }.IW 9* S
' ~
~-
,g f d l'.
ENFORCEMENT ACTION WORKSHEET , 9H27
. c ST. LUCIE UNIT 1 CONTAINNENT PIG IN0PERABILITY 7 . .
PREPARED BY: Mark S. Miller DATE: April 8, 1996 , NOTE: The Section Chief of the responsible Division is resportsibleior prepa this EAW and itr i distribution to attendees prior to an Enforcement Panel. The Section Chief shall also be responsible for i providing the meeting location and telephone bridge number to attendees via e-mail [ENF.GRP, CFE,
- OEMAIL, JXL, JRG, SHL, LFD; appropriate Ril.DRP, DRS
- appropriate NRR, NMSS). A Notice of i Violation (without "boilerplate") which includes the recommended severity level for the violation is l required. Copies of applicable Technical Specifications or license conditions cited in the Notice or other reference meterial needed to evaluate the proposed enforcement action are required to be enclosed.
^
This Notice has been reviewed by the Branch Chief or Division Director and ! each violation includes the appropriate level of s ecifi s to how and l when the requirement was violated. . 8N ~
' Si a}ure
- f. ppg M p O dd c Facility: St. Lucie M /
" g"h l Unit (s): I g/uw M f, .g i
Docket Nos: 50-335 License Nos:'DPR-67 c.<W m . j - Inspection Report No: 96-04 /
- Inspection Dates: 2/18-3/30/96 /N/d
- l . Lead Inspector: N. N111er i
- 1. 'Brief Summary of Inspection Findings: Failure on the part of a health Physics technician to follow a procedure resulted in inoperability of a i
containment Particulate-Iodine-Gaseous (PIG) monitor. The technician !- failed to open a valve which was closed to obtain a containment air . sample. The closed valve resulted in severely restricting the flowpath from the containment atmosphere to the containment PIG, rendering the
- instrument inoperable. Several non-licensed operators logging data j failed to identify the problem over a three day period. Resultant j inoperability resulted in licensee performing a reactor startup without i
satisfying the TS LC0 for RCS leakage detection, in that the PIG was required to satisfy the RCS leakage LCO.
- 2. Analysis of Root Cause
Failure to follow procedure, followed by inadequate log reviews and lack of a questioning attitude on the part of NL0s.
- 3. Basis for Severity Level (Safety Signi"icance): Supplement I, D1. The
, safety significance of the issue is low. The monitor in question serves to provide indications of containment environment for identification of' j RCS leakage. It is backed up by separate containment radiation PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
((' f
j..
- p- maonitors, c
- ntainment pressure instrumentation, and containment
- ~ temperatura-indications. However, this example includes the failures of
- a number of personnel to perform as required and indicates that the i
licensee has not been successful in stemming the tide of personnel i attention-to-detail and procedural compliance issues. There should be a strong cover letter commenti
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
[by EAi, Supplement, and identification date.] _ _ _ . _ . _ . _ , _ _ -
-e EA 95-180, Supplement I, 8/9/95 - Inoperable PORVs due to
- maintenance and testing problems (SL III, $50,000 CP)
, o EA 96-040, Supplement 1,1/22/96 - Overdilution due to operator i i inattention (SL III, $50,000 CP) Issued on 3/28/96; licensee response not received yet. !. 5. Identification ~ Credit? Yes ): Consider following and discuss if applicable below: X Licensee-identified - O Revealed through event O NRC-identified j O Mixed identification X Missed opportunities l Enter date Licensee was aware of issues requiring correctiva action: } [2/24/96]
- , Explain applf cation of identified credit, who and how identified and
- consideration of missed opportunities
- .
- s Condition was identified by licensee when a chemistry technician noticed low flow through the PIG while passing by the component. However, non-licensed operators logged the unacceptably low flow value on six occasions with an electronic data logger which required the NL0s to enter the data twice each time (because the data was out-of-spec).
- 6. Corrective Action Credit? Yes Brief summary of corrective actions:
e Monitor returned to service .
^
e HP technician counseled / disciplined e Ops enhanced log reviews e HP revised air sampling procedure to include independent verification of valve positions following sampling e HP reviewed event with all technicians e setpoint for low flow switch under evaluation (switch was set to alarm at zero flow, but valve position allowed small amount of flow which, while inop'g PIG did not bring in alarm) Explain application of corrective action credit: Corrective action were appropriate to this circumstance in the short term; however, the licensee's treatment of the extent of condition may not be comprehensive enough. To date, the ' licensee has not identified those components operated by departments other than Operations whose operability could be affected during normal sampling. Corrective actions for previous events involving operations' logging practices and. overall site procedural compliance should have prevented this event. PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
? .
- 7. Candidate Ftr Discretion? [See attached list) [Yul:
i Explain basis for discretion consideration: j Potential candidate for escalation over the apparently low safety significance, as it involves particularly poor licensee performance, l involved a number of operator failures, and involves issues of attention j to detail and procedural compliance which have been a repetitive theme - in the last 8 months.
- 8. Is A Predecisional Enforcement Conference Necessary?
4 No i
- Why
- .
1 i However, the violations should be cited to determine what the licensee i will do, as regards operator attention-to-detail, in response to this
- event, which is different from other corrective actions taken in the ;
l last 8 months. . } If yes, should OE or OGC attend? j Should conference be closed? l
- 9. Non-Routine Issues / Additional Information:
i- 10. This Action is Consistent With the Following Action (or Enforcement Guidance) Previously Issued: Supplement I.D.1 l
- I i !
- 11. Regulatory Message:
Operator attention to detail, a questioning attitude, and a commitment j - to the highest standards of performance are paramount in providing a i j barrier to individual failures. ' ! 12. Recommended Enforcement Action: SL IV with a strong cover letter comment. Not a candidate for NCV due j i to the number of previous enforcement actions (and subsequent corrective l actions) based upon failures to follow procedures issued in the last two l years. ) 13.- This Case Meets the criteria for a Delegated Case. No
- 14. Should This Action Be Sent to OE For Full Review? To be determined. l t
If yes why: ' i l
- 15. Regional Counsel Review To be obtained at the panel.
No Legal Objection Dated: PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE
. WITHOUT THE APPROVAL OF THE DIRECTOR, OE l
)
1
,'16. Exempt from Timelines: No Basis for Exemption: .
- Enforcement Coordinator:
J DATE: i I 4 i 4 } PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE , t
1 ENFORCEMENT ACTION WORK $NEET - ISSUES TO CONSIDER FOR DISCRETION < ~* O Problems categorized at Severity Level I or II.. O Case involves overexposure or release of radiological material in excess -
- of NRC requirements. *
[
.X Case involves particularly poor licensee performance.
! O Case (may) involve wi11 fulness. Information should be included to
- address whether or not the region has had discussions with OI regarding the case, whether or not the matter has been formally referred to 01,
- and whether or not 01 intends to initiate an investigation. A-description, as applicable, of the facts and circumstances that address the aspects of negligence, careless disregard, wi11 fulness,. and/or management involvement should also be included.
.O Current violation is directly repetitive of an earlier violation.
/
- O Excessive duration of a problem resulted in a substantial increase in risk.
O Licensee made a conscious decision to be in noncompliance in order to ! obtain an economic benefit.
- i 0 Cases involves the loss of a source. (Note whether the licensee self-
- identified and reported the loss to the NRC.)
1 O Licensee's sustained performance has been particularly good. i i X Discretion should be exercised by escalating or mitigating to ensure
- that the proposed civil penalty reflects the NRC's concern regarding the
- . violation at issue and that it conveys the appropriate message to the i '
licensee. Potential candidate for escalation over the apparently low
- safety significance,- as it involves particularly poor licensee ,
i performance, involved a number of operator failures, and involves issues [ of attention to detail and procedural compliance which have been a j repetitive theme in the last 8 months. i i 1 j .. - 4 i i
)
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE ] WITHOUT THE APPROVAL OF THE DIRECTOR. OE ,
. . . ... _ . . . - . - . . _ - . .- - _ . . . . . - . - - . - . - . . - . . - . - ~ - - . . . _ -
. Enclosure 3 i REFERENCE DOCUMENT CHECKLIST i
L [X] NRC Inspection Report or other documentation of the case: NRC Inspection Report Nos.: 96-04 excerpt ! [X] Licensee reports: 335/96-03 4- [X] Applicable Tech Specs along with bases: . \ i- Applicable license conditions [- ] 1 1- , i l j [X] Applicable licensee procedures or extracts 1 ; !. .[] fopy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results j
=
[] Extracts of pertinent FSAR or Updated FSAR sections for citations
- j. involving 10 CFR 50.59 or systems operability i
[ [] Referenced ORDERS or. Confirmation of. Action Letters i [] Current SALP ' report summary and applicable report sections j '. i ] [] Other miscellaneous documents (List): ! l PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
. . - -.-.- .-.---.-.- ~ - - - . - - - - -
+ l i -
. 04.2 Unit 1 Containment PIG Rendered OOS Due to Personnel Error
!' Following the Unit I trip of February 22, a number of containment l l entries were made to troubleshoot CEAs. In preparation for one such ' entry, an HP technician.was dispatched to obtain a grab sample of the I containment atmosphere at 1:55 p.m. on February 22. The methodology for i obtaining the sample involved attaching a removable air sampling device to quick disconnect fittings which placed the device in a parallel path l to the air flow moving through the PIG unit. A valve (procedurally designated as valve 3) located between the quick connects was.then to be j throttled closed to force the air flow through the sample devict at a predetermined rate. A sample was then to be taken for a minimum of 30 minutes, at which time the throttle valve was to be returned to its open position and the sample device was to be isolated at the quick , disconnects and removed from the unit. ! When the HP technician performed the sample, he failed to return the throttle valve to its open position. The result was that flow through the PIG was reduced to approximately 15% of the intended value, rendering the PIG inoperable. The licensee's investigation of the event revealed that the HP technician failed to employ HPP-22, revision 2,
" Air Sampling." Step 7.5.1.R required that upon completion of the .
sampling, that valve 3 be returned to the full open position. In fact, the subject step was proceeded by a caution statement stating that valve 3 must be returned to the full open position. The failure of the HP technician to employ the governing procedure for obtaining air samples is an apparent violation of 10 CFR 50 Appendix B, Criterion V, which ) requires that activities affecting quality be performed in accordance ' with documented procedures (VIO 96-04-XX, " Failure to Employ Procedure for Obtaining Containment Air Sample"). The PIG remained in its inoperable state until February 24,-when a l chemistry technician performing an unrelated task noted the indicated l flow through the PIG at a value much lower than normal (a fractton of l one SCFM, vice 2.5 to 3.5 SCFM required by procedure), which resulted in ; the identification of the PIG's inope-ability and its return to service. ! During that time, SNP0s recorded the lower-than-normal flow values during logtaking rounds once per shift. Operators employed data loggers (small hand-held computers) to take logs, and when a given parameter was sensed by the computer, the operator was prompted to enter the data again to verify that the out-of-specification value was, indeed, the intended value. In the case of PIG air flow, SNP0s logged the data tv: ice each round without pursuing the cause for the low reading. AP 0010120, revision 79, " Conduct of Operations, Appendix F, " Log
- Keeping," stated, in part, " Log readings shall be compared to previous readings to detect abnormal trends or conditions and verified to be within the minimum and maximum values for that parameter. All log readings outside the min / max values shall be circled with reasons stated for abnormal readings..." The failure of SNP0s to identify the low flow condition of the Unit I containment PIG and to provide reasons for the observed performance is an apparent violation (VIO 96-04-XX, Failure to-Identify Adverse Trends During Log Reviews). Additionally, the PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
- l j
direction that out-of-specification values should be " circled" indicated that the procedure was not current, as the direction was a cleat reference to paper logs (the predecessor of the data loggers), which had j not been employed for some time by SNP0s.
- TS 3.0.4 stated that " Entry into an OPERATIONAL MODE or other specified
- j. applicability condition shall not be made when the conditions of the i Limiting Condition for Operation are not met..." Unit 1 entered Mode 2 i
j on 5:13 a.m. on February 24 with the containment PIG inoperable. TS ( 3.4.6.1 requires the PIG to. be operable in mode 2. This is an apparent ! violation (VIO 96-04-XX, " Failure to Satisfy a Technical Specification
- Limiting Condition _for Operation Prior to a Mode Change").
l The inspector reviewed the licensee's discussion of the event in LER 335 96-003-00, " Containment Particulate and Gaseous Monitor Out of Service i Resulting in a Condition Prohibited by Technical Specifications Due to l Personnel Error." -In the LER, the licensee described corrective actions j which included: j 1 ! e Disciplining the HP technician involved'in the event. l e Enhancement of both units' logs to include a written explanation for out-of-specification readings.
- e Incorporating sign-offs in HP procedures for actions involving the manipulation of plant equipment.
! e Reviewing the event with HP personnel emphasizing procedural. l compliance. l The inspector reviewed revision 3 to HPP-22, and noted that the new I revision included requirements that the control room be notified at the ! beginning and end of containment sampling (new requirements) and that independent verifications be made of valve positions following~ sampling. Similar changes were made to the procedure for Unit 2 sampling. The inspector discussed the event with the Operations Supervisor and I asked whether,- in the past, the PIGS were declared inoperable when sampling occurred and was informed that they had not, but that they would in the future. The inspector then requested a list of activities performed by organizations outside Operations, that could affect operability of TS components in ways similar to the subject event. The licensee identified... In summary, the inspector found that the undetected inoperability of the ,
~s ubject component was the result of not employing a procedure while performing a grab sample. The condition was extended in time due to inadequate logtaking on the part of non-licensed operators and
, inadequate review of the logs taken. As a result of these failures, a
-violation of TS occurred when a reactor startup was performed wi,th the component 00S. Additional weaknesses included a logging procedure which was not up-to-date, and an historical failure on the part of Operations to declare the containment PIG 005 when grab sampling was taking place.
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE '
_ _ _ _ . _ _ __ _ _ _ _ _ _ _ _ ._ __ . . _ . . _ . _ . _ . _ .m.. PROPOSED VIOLATIONS
- i .
J l Technical Specification 6.8.1.a requires that written procedures be , established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February,1978. Appendix A, paragraph 1.d includes administrative procedures for procedural adherence. QI 5-PR/PSL-1, Revision 68, " Preparation, Revision, Review / Approval of Procedures," Section 5.13.1, states that all procedures shall be strictly
- adhered to.
Contrsry to the above: ,
- a. Step 7.5.1.R of procedure HPP-22, Revision 2. " Air Sampling," required i
i ' that valve 3 of the Unit I containment Particulate Iodine Gaseous. ! Monitor be returned to the open position following the )erformance of a 1 j containment grab sample. On February 22, 1996, a healti physics technician performing a grab sample of the Unit I containment failed to
- return valve 3 to the open position and, as a result, rendered the monitor inoperable.
~
), i b. AP 0010120, revision 79, " Conduct of Operations, Appendix F, " Log ; j . Keeping," required, in part, that " Log readings shall be compared to l previous readings to detect abnormal trends or conditions and verified I to be within the minimum and maximum values for that parameter. All log ! readings outside the min / max values shall be circled with reasons stated l l for abnormal readings (i.e., 00S, NPWO, ISOL, etc)." On February 22, ; 23, and 24, Senior Nuclear Plant Operators failed to perform adequate l reviews of logs taken in the Unit 1 Reactor Auxiliary Building, as the ' i out-of-specification log readings taken on the Unit I containment particulate iodine gaseous monitor were not hilighted and explained. As , a result, the Unit I containment Particulate Iodine Gaseous monitor ! remained inoperable and Unit I transitioned from Mode 3 to Mode 2 i without satisfying Technical Specification Limiting Condition for i Operation 3.4.6.1. The Mode transition was prohibited by Technical - j - Specification 3.0.4. ! This is a Severity Level IV violation (Supplement I) i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE
. WITHOUT THE APPROVAL OF THE DIRECTOR, OE
FloridJ Power & Ught Conosey, P.O. Bos 13. Fort Pieros, FL 34I56413 O y ... . . . . . . . . . . w
. . . . . . . . . . . . . . . . . . ..._.._w, L-96-70 10 CFR 50.73
- 0. ;., . . .i
.T -7 ' A 9 . S. e U. S. Nuclear Regulatory Commission Attn: Document Control Desk -
Washington, D. C. 20555 Re: St. Lucia Unit 1 - -- Docket No. 50-335 Reportable Event: 96-003 Date of Event: February 24, 1996 ~ ~ " - - - Containment Particulate and Gaseous Monitor Out of Service Resulting in a Condition Prohibited by Technical Specification Due to personnel Errer The attached Licensee Event Report is being submitted pursuant to the requirements of 10 CFR 50.73 to provida notification of the - subject event. Very truly yours,
$W ,
W. H. Bohlke Vice President St. Lucia Plant WHB/SL , Attachment cc: Stewart D. Ebneter, Regional Administrator, USNRC Region II Senior Resident Inspector, USNRC, St. Lucie Plant i Dov
-8 b& I W 16 an FPL Group company
\
_ _ _. _ _ _ _ ~ . . _ _ . _ _ _ _ _ . _ . _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ ! IIAo PORM aos u.S. tuta.sAA RaoutAToRY CoMMasasong assamuu.sv ens us.t.senesen i to.est sem some !. #'"l' llDll'7'"llNIEueE"""E""T* ".'e."",,' m =",.a." i LIcruszz avzur maromT (Lza) 2 -- a i tsw rever= for required numoer of. '.~_ E'*"'."*.%"E".".*.*m".'".".* L.t'.t.:F.E" ".JlllU..u.=.=m.u, **.".,'ll.".e".".e."::lr.t.
. . Wee .e . .
l d'Oits/ characters for each blocid ! paanwrv maansin seemstsimamis. suasa f ST LUCIE UNIT 1 06000335 1OF6 ) was Containment Paraculats and Gassous Monitor Out of Service Resulting in a Condation Prohibited by Technical Specificanons Due to Personned Error ! .Z.T DATP #El iBt 9p- tm C.J DAfr f71 E SAPWmERIAfnLWEDAm ~ l cacanv manas -enemen hMurnt DAY YEAA YEAR RNuffM oAY YEAR pasa nyanness samurenesamt j 2 24 96 96 - 003 - 00 3 25 96 08000 $ Th'8 R i=T l' k""TTre pun nuan,Y To Tur menin;mstr rn M 1e erst a. vtha, ; OpstAT984 g m, esis ! MODE tel 2o.22ot ttd to.22o3teH21tvl X So.73teH210) W.734eNIlhal ' g 90 99n1ralf11 96 990sf ntstff) En Tsfanf 9tful MT**"---_^ ' q 1. EVE. llel 2o.22o3 tam 210) 2o.22o3(aH3)M So.73 tam 2MEl 73.71
"' - - - - ~
9e 99mstair9tnn 9e 99est.)#al ! en Tsrairstad oT M l , l . ,K 2o.22o3teH25tlin to.3steHil Go.73taH2Hvl aseseren Atammes besser i l 2.7 1 N M _s i 2o.22o3teH210vl So.3steH2) So.73taH2Hvin ) i seawasy comrTAc7 ron Twis a rut r191 Inames TRpteousE asunaam enmaans A,es Caed Sean Lavelle, Ucensing Department (407) 467-7160 _ _ l entastrTF nus t twr ron raew enusonsenry rai t tint ermeeimsvi M Twts napont rist
- ,m._
7,, ",M, sysT:na g conwi'l AM l
- t. Aunt sysTths cc MPcN ert taAsu AcTunsR h e
cAuss uAssuPAcTuREL t I $1.1P99 rMNnf7At REpost? rYPEcTED f1at E h000nN OAV YEAR l ygg an smaanmannas M y.s. comoset. EXPECTED susMissioN oATEl. X M DATE(151 AssinAcT tumi t i400 so . i.... amor.=wn.imY 15 enes e typewnmn kn I ties On February 22,1996, at 1355, with St. Lucie Unit 1 in Mode 3, a health physics (HP) technician drew an air sample of the Unit 1 containment atmosphere. The sample was obtained from the containment atmosphere particulate and gaseous monitor (CAPGM). Upon completing the sampling, the technician did not reopen the valve to the monitor as required by procedure. On February 24,1996, with Unit I in Mode 2, a chemistry technician noticed the monitor's process flow meter reading low. A chemistry supervisor verified the isolation of the monitor and reopened the inlet valve to the sample pump. The flow returned to normal and the monitor was declared Operable. l The primary cause of this event was personnel error attributed to the HP technician for not following procedure. In addition, the flow f ault indicator did not illuminate and operator logs with low flow entries were not questioned. During the time the monitor was out of service the reactor t.svity sump level and flow monitoring system was Operable, and 24 hour sampling of the containment atmosphere was ongoing. Corrective actions for this event : 1) The CAPGM was placed back in service. 2)The HP technician was disciplined and counseled on plant policy on procedural compliance. 3)The operations department enhanced he review of operator logs, for both, units to include a written explanation for any reading outside its normal value.4) HP is incorporating sign offs to both units' procedures.5) HP supervision has reviewed this event with all HP technicians empnasizing the severity of this event and management expectations. 6) Engineering will determine set point range for the low flow switch. 7) Chemistry procedure will be revised to include a calibration and functional test of the flow switch.
NRcpoRM 3444 U.a. NutKaAA mm m i M66 i LICENSEE EVENT REPORT (LER) TEXT CONTINUATION } paen rfy wanas m ni-- - - i ' 8R * ^^ iet tm 8E YEAAI m I ST. LUCIE UNIT 1 05000335 2 0F 6 1 96 - 003 - 00 TEXT r# more spese a regiares, aos eseammet senses et Mtc /s,m J654J M7) l l DFECRIPTION OF THE FVFNT On February 22.1996, at 1355, with Unit 1 in Mode 3, a health physics (HP) technician sampled the containment atmosphere in preparation for a containment entry following the manual trip of the unit. in I accordance with the HP procedure (HPP-22), the sar'spie was taken from the containment atmosphere i particulate and gaseous monitor (CAPGM) (Ells:lO which monitors particulate and gaseous radiomativity. , , The sample is obtained (see page 6 FIGURE 1) by connecting, vis quick disconnect fittings, a removable ai. ! j sample collection device, then opening valves on both sides of the sample collection dowce (valves 2 and f ! j and throttling the inlet valve (valve 3) to the monitor sample pump. After the sample is 9sthered the vaive )
- (valves 2 and 6) to the sample collection device are closed, the inlet valve (valve 3) to the monitor sample !
j pump is reopened. In this event, valve number 3 was not reopened as required by procedure, and flow to , the monitor sample pump was reduced to approximately 15% of the normal design flow. l On February 24,1996, with Unit 1 in Mode 2, a chemistry technician noticed the monitor's process flow meter reading low. A chemistry supervisor and the technician verified that valve number 3 was throttled and flow was being impeded. They opened the valve fully and flow returned to expected value. The contn room was notified of the inoperable monitor and it was declared out of service from the time the HP ichnician took his sample on February 22 until its return to service at 1210 on February 24,1998. The
.ow fault switch did not provide indication because it was adjusted to illuminate on zero flow. An evaluation was initiated to determine if the monitor was Operable at the reduced flow during the time valv number 3 was throttled.
r.'At]SF OF THF FVENT The root cause of the event was personnel error by the HP technician. The technicit.n did not follow the procedure which instructed and cautioned him to reopen valve number,3. The technician did not have the procedure with him while taking the sample. There were three contnbuting factors that impeded the identification of the monitor being inoperable. Firsi the lack of sign offs in the procedure contributed to the technician performing the evolution without the procedure in hand. Second, the flow fault indicator switch did not illuminate in the control room, and thirc the low flow readings taken on the operator locs while the monitor was inoperable were not questioned b-the operators recoroing them nor the licensed operators reviewing them.
> SAC FORM 366A M-951
* ~
1 j uncpaansaena 4 m u.a.mucurAn nestaAvestscensumou .i LICENSEE EVENT REPORT (LEM j TEXT CONTifdtfATION n ,- rry = = m n c_ - . i sm C ini -m i ST. LUCIE UNIT 1 M M M i 05000335 3 0F 6 4 96 - 003 - 00 TEXT tr . _. asese me inesraer, use oestemas# senses educ Form Jaso (171 i ANALYRIR OF THF EVENT l This event is reportable under 10 CFR 50.73 (aH2)(1) as 'any operation or condition prohibited by the plant 1 Technical Specifications". The containment atmosphere particulate and gaseous monitor was inoperable. An j evaluation determmed the reduced flow through the monitor would cause the particulate monitor to err ki a i nonconservative manner. The isokinetic nozzles are sized for a specific flow rate. There is e Enear ~
) relationship between the detector efficiency and the sample flow rate when the filter speed is held j constant. With the sample flow speed reduced to 15% of normal, the detector efficiency is reduced by !
85%. The gaseous channel was also determined inoperable due to the inability to conclude that the reduced i flow through the gas monitor was sufficient to accurately detect an increase in gas activity. The redumd , I flow rate was at the low end of the flow meter scale. An indication from a flowmeter operating at this t extreme end of the scale cannot be used. - The inoperable monitor did not meet Technical Specification 3.4.6.1
- Reactor Coolant System Leakage". ,
This Technical Specification requires that the CAPGM and the reactor cavity sump level and flow morutoring i system (RCSLFMS) (Ells:lJ) be operable. The unit entered Mode 2 during the time the monitors were { inoperable. In accordance with Technical Specification 3.0.4., entry into an operational mode shall not be ade when the conditions of a Limiting Condition for Operation are not met. The Technical Specification required action for the inoperable monitor are 1) the RCSLFMS be operable. 21 appropriate grab samples are obtained and analyzed at least once per 24 hours and: 3) a reactor coolant
! system (RCS) water inventory balance be performed at least once per 8 hours during steady state
}; operation. j in this event the RCSLFMS was Operable. Additionally containment atmosphere was sampled every 24 hours per procedural guidance (HPP 23) for entries into containment during the unit shutdown. The RCS water inventory balance was performed once per 24 hours in accordance with operations daily survesitances (AP-1-OO10125, Check Sheet 2) and the results were within Technical Specification limits. The 8 hour action requirement for RCS water inventory balance was not adhered to since it was not known that the
! containment monitor was out of service and the unit was not continually at steady state operation.
1 l In the unlikely event of a RCS leak the control room operators would have been alerted to this condition by i an increasing trend in the reactor cavity sump level monitor, by an increase in activity on the daily samples of containment atmosphere, and an increase in leakage on the RCS water inventory balance. Based on the above conditions, the health and safety of the public were not affected by this event. i
. ._..s.........: ..~.....=~.~.~ -
NRC poses asea uA.CuoLEARIWSERATEMY eggsasse 14 886 LIcEEsEE ETMfT REPORT (LEL) j I j TEXT CONTINUATION i sam vrv enaman eti r.. - - - i- tm w- Ime - em M l ST.1.UCIE UNIT 1 05000335 4 0F 6 96 - 003 - 00 1 TEXT (# more spese a reewsw. see sessones senses et Awc rome JosM (171 i CORRECTtVF ACTIONE I
- 1. 7th containment atmosphere particulate and gaseous radioactivity monitor was placed back in service. '
___:....:.-~..
- 2. The HP technician was disciplined and counseled in plant policy on procedural compliance.
i
- 3. The operations department enhanced the review of both units operator logs to include a written I explanation for any reading outside its normal values.
- 4. Health physics is incorporating sign offs, in both units' procedures. for manipulation of plant equipment that involves lengthy and or complicated steps.
- 5. Health phys',cs supervision has reviewed this event with alt HP technicians emphasizing the severity of I this eveit and management expectations for procedural compliance.
8i. Engineering will determine the appropriate set point range for the low flow switch
- 7. Chemistry procedure 1-C-67 will be revised to include a calibration and functional test of the flow switch to ensure there is no set point drift.
AnnmnNAL INFORMAT1nN 11 f'nmannant Fail"ra= NONE
- 2) prnvinne Rimiinr Fvante LER 335 92-001 " Fuel Handling Building Ventilation Monitor Out of Service Resulting in a Condition Prohibited by Technical Specifications Due to a Personnel Error' This event was attriuted to a chemistry technician not restarting the fuel handling building stack monitor sample pump after taking a sample.
j , HRo Popes 3084 uA.NumaARIWSERATENIT emangum j 4 . West LIcaussa sysur mapoar (m ! TEXT CONTliiUATION I saemery - en r___-.- ma ase- im em yggg N N t 1 m M l ST.LUCIE UNIT 1 05000335 5 0F 6
- 96 - 003 -
00 TEXT I# more asese ar toenmot ame eespooner sesses er AMC rome Jd84 (171 1 i t { ADumONAL INFORMATION , i I 4 . I (Continued) =- j 2) Previous Similar Events j _ . . . . _ LER 335 92-003
- Containment Atmosphere Particulate and Gaseous Radioactivity Monits/s Out of Service Resulting in a Condition Prohibited by Technical Specification Due to Personnel Error' his event was attributed to the control room licensed operator leaving the containment isolation valve on the monitor closed after surveillance testing.
In House Event " Unit 1 Containment Radiation Monitor Out of Service Due to a Mispositioned 94-73 Valve" This event occurred due to a HP technician leaving valve number 3 closed due to inadequate labeling after a plant change modification was made. l
.. . .. . . - . _ - _ . _ . . _ . . ~ . . _ . _ . . _ - . - - . - _ - . . . - . _ _ _ _ . . _ . . ~ _ .
~
- IIRC FORM 364A U.S. NUCLEAR R884AATORY CORAMEun ,
4 m .._ , . LICENSEE EVENT REPORT (LER) a TEXT CONTINUATION i 4 yace,try unar su - , m ., i en w --- ' en eag,g3L,,,
- YEAR SEQUENTIAL REVISION
- i . LUCIE UNIT 1 05000335 6 OF 6 l 96 - 003 -
00 l TEXT W more speee an reeenrol une eensional conne et NRC hwm J6&Al (118 i, 4 aAu. valves
- su.OTHER
- m v4LvEs> :
I \ ] a 7, U
'[---- Hl I I
841 1 q g 'l- - - - - ... - H F we p. A kg i {\\\\\ 84340$DET. ' O i CourmOL PANEL l 2 j &# j m ue m "' FILTER HOLDER
- wisELF LOCK 5
, OtSCONNECT l .t i
/
"/ A v
pi\ 1
\
Q ouscK l SAMP PUMPS F1 d L
/ DISCONNECT 5 N
a - 2 I
%,r-
__ 3 - 12 % i PUMPING By.PAgg e l SYSTEM Jm i Q 117 VAC. 10 r , SING By. PASS W M ~mm i PMASE SOLUTION s "T" I M j INLET ef , 641&J SAMPLER W/3' Pb [j 74 PURGE N.C. ANEL ! S43 20 $ DET. V- BY-P W i l xxxxxxx= 3,- d L SOUmON DRAM i i a 646-5-50 ENCLOSURE MS TB j __ __ _ _ -1 , mas,- i _ j _ . _ i l Fieure 1 1 I 4 d Nec Fons as4A 64-066
l - - - - Pase: . --; , = ,. nuvaan ucu . PnocuounsTm.s: ! 2 AIR SAMPlJNG~ 15 of 25 [ PRocsDuns No _ . . . , .._ HEALTH PHYSICS PROCEDURE . ' , -, ST. LUCIE PLANT l HPP-22 ! 7.0 INSTRUCTIONS: (continued) 1 7.5 (continued) . 1 ! 1. (continued) . . . - l G. Attach a piece of tygon tubing from the charcoal cartridge elds' _ l' of the remote air sampling head to the vacuum gauge, j . 3 f H. Connect the rotameter upper position tygon tubing quick . l disconnect to the SAMPLE TRAY OUTLET female quick ' _ disconnect. 4 i
- l. Open valves (#2 and #6) that are IM behind the FROM
! RCB - SAMPLE TRAY INLET connector. Valves are open l when the handle is parallel to the pipe. 4
-- J. Throttle the third valve, labelled 3 and located inside the bsck l panel on the right side, until the desired flow rate (typically l
101pm) is obtained on the sample tray.
- l I K. Observe the vacuum gauge reading (inches of Hg) and allow the reading to stabilize.
L Compare the indicated flow rate and the vacuum gauge reading to the corresponding values in Table 3. M. If necessary, adjust the indicated flow rate to a flow rate that is correct for the vacuum gauge reading. Use valve 3 located in ' the electronics cabinet.- N. A sample should be collected for 30 minutes to obtain a total flow of 3.0E + 05 mL O. Tum OFF both valves (#2 and #6) located behind the FROM RCB - SAMPLE TRAY INLET connector. Valves are in the OFF position when tumed perpendicular to the piping. P. Close the stopcocks (i.e., tum horizontal) on the Marinelli flask simultaneously. Q. Remove the FROM RCB - SAMPLE TRAY INLET and the SAMPLE TRAY OUTLET quick disconnects.
navisum no.: enocuounstm.s: y , l 2 AIR SAMPLING _ 16 of 25
,, enocuounano.: ,
,? HEALTH PHYSIGS PROCEDURE 4.. . HPP-22 ST. LUCIE PLANT 4 7.0 INSTRUCTIONS: (continued) . . . .
s.
- ._ - 7.5
- 1. (continued)
{ CAUTION " Valve M must be retumed to a full OPEN g-+"'=i after stui$.g is ) {) complete. ,
. ? ,
. . __. .._ 7 !
I{ R. Tum valve M to full open; i.e., parallel to the piping. d l y .
- S. Vertly that at least one of the two Hastings mass flowmotors i has approximately 3 scfm (2.5 - 3.5 scfm). If not, contact the l 1
Chemistry Department immediately. N, T. Ve tw o n does not have a FLOW FAULT. If both pumps have a FLOW FAULT, contact the Chemistry Department immadiately. U. Take the air samples to the count room for analysis. V. Particulate sampling can not be performed using the Unit 1 RCB remote system. There is a fixed filter upstream of the remote air sample tray connections. Enter NA in the Air Sample Log book and on the HPP-22.1 Air Sample Data Sheet for the particulate analysis results.
- 2. Unit 2 Coritainident Atni6iiphere Air Sample 7
UNIT 2 RCB REMOTE AIR SAMPLING TRAY CONNECTIONS DIAGRAM
~ ~~
RCB FEED 4 MARINELLI 1 PARTICULATE /' CHARCOAL CARTRIDGE SAMPLING HEAD 1 VACUUM GAUGE 4 ROTAMETER 1 SUCTION /R2
__7 1 l 3/4 LfMITING CONDITTONS FOR OPERATION AND SURVEILLANCE REOUIREMENTS 5' 3/4.0 Appl!CA8ILITY . i .:5 l l LI'1! TING CONDITION FOR OPERATION . i 3.0.1 Compliance with the Limiting Conditions for Operation (LCO) contained in i i
! the succeeding specifications is reouired during the OPERATIONAL MODES or other j
conditfons specified therein; except that upon failure to meet the Limiting Conditions for Operation, the associated ACTION requirements shall be met. i 3.0.2 Noncompliance with a specification shall exist when the requirements of } the Limiting condition for Operation (LCO) and associated ACTION requirements l are not met within the specified time intervals. If the Limiting Condition for Operation is restored prior to expiration of the specified time intervals, { completion of the ACTION requirements is not required.
~
! 3.0.3 When a Limiting Condition for Operation (LCO) is not met, except as i ' provided in the associated ACTION requirmnents, within I 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 ! 1 At least HOT STAND 8Y within the next 6 hours. - j 2. At least NOT SHUTDOWN within the following 6 hours, and i 3. At least COLD SHUTDOWN within the subsequent 24 hours. i
- Uhere corrective measures are completed that permit operation under the
' ACTION requirements, the ACTION may be taken in accordance with the specified time limits as measured from the time of failure to meet the LCO. Exceptions to these requirements are stated in the individual specifications. This specification is not applicable in MODES 5 or 6. i l 3.0.4 Entry into an OPERATIONAL '100E or other specified appitcability condition ! shall not be made when the conditions of the Limiting condition for Operation are not met and the associated ACTION requires a shutdown if they are not met j within a specified time interval. Entry into an OPERATIONAL MODE or specified i condition may be made in accordance with ACTION requirements when conformance I' to them permits continued operation of the facility for an unifaited period of time. This provision shall not prevent passage through or to 0PERATIONAL MODES as required to comply with ACTION statements. Exceptions to these
- requirements are stated in the individual specifications. '
i i
. 4 l
i . d i l , i ST. LUCIE . UNIT 1 3/4 0-1 Amendment; No. 40,FS,103 i < l
, -w m
-.r-..---
j ApPLICA8ILITY -" - f* BASE 5 - l . The same principle applies with regard to the allowable outage One Ifmitis of
- - the ACTION requirements. if compliance with the ACTION requirements for one i
speciffcation results in entry into a MODE or condition of operation for another
' specification in which the reautrements of the Limiting Condition for Operation
, are not met. If the new specification becomes aopitcable in less time than i specified, the difference may be added to the allowable outage time limits of l the second specification. However, the allowable outage time limits of ACTION i requirements for a higher MODE of operation may not be used to extend the ! allowable outage time that is applicable when a Limiting condition for Operation l is not met in a lower M0DE of operation. 1 The shutdown requirements of Specification 3.0.3 do not apply in 200ES 5 ! and 6, because the ACTION requirements of individual specifications define the i remedial measures to be taken. _ _ l i 3.0.4 This specification establishes limitations on MODE changes when a Limiting ! Condition for Operation is not met. It precludes placing the facility in a higher it00E of operation when the requirements for a Limiting Condition for Operation are not met and continued noncompliance to these conditions would - result in a shutdown to comply with the ACTION requirements if a change in N0 DES were perinitted. The purpose of this specification'is to ensure that facility operation is not initiated or that higher MODES of operation are not entered when corrective action is being taken to obtain compliance with a ! specification by restoring equipment to OPERA 8LE status or parameters to i specified limits. Compliance with ACTION requirements that permit continued operation of the facility for an unlimited period of time provides an accept-able level of safety for continued operation without regard to the status of 4 the plant before or after a MODE change. Therefore, in this case, entry into ! i an OPERATIONAL MODE or other specified condition may be made in accordance i i with the provisions of the ACTION requirements. The provisions of this ' i specification should not, however, be interpreted as endorsing the fatture to i exercise good practice in restoring systems or components to 0PERABLE status l before plant startup. 1 i When a shutdown is required to comply with the ACTION requirements, the ! . provisions of Specification 3.0.4 do not apply because they would delay placing ] the facility in a lower MODE of operation. , Exceptions to this provision have been provided for a limited number of specifications when startup with inoperable equipment would not affect plant safety. These exceptions' "are stated in the ACTION statements of the appro-j priate specifications. - 1
%)
ST. LUCIE - UNIT 1 5 3/4 0-3 .Naandment !!o. ff,N ' 1 ,
t
- .. ...a 6.0 ADMINISTRATIVE CONTROLS ,
) - _~ , j c. The Safety Limit Violation Report shall be submitted to the Commis-sion, the CNR8, and the President - Nuclear Division within 14 days of the violation.
- d. Critical operation of the unit shall not be resumed until authorized. l by the Cossiission.
i j l 6.8 PRDCEDURES AND PROGRAMS . l l 6.8.1 Written procedures shall be established, implemented and maintained ! covering the activities referenced below: .. . . . _ . . .
- a. The applicable procedures recommended in Appendix "A" of Regulatory i Guide 1.33, Revision 2, February 1978, and those required for ~~
~
implementing the requirements of NUREG 0737.
- b. Refueling operations.
! c. Surveillance and test activities of safety related equipment. i
- d. Security Plan implementation. ]
' ~~ ~
l e. Emergency Plan implementation. l l: f. Fire Protection Program implementation. i ! l g. . PROCESS CONTROL PROGRAM implementation. e
- h. OFFSITE DOSE CALCULATION MANUAL implementation.
- i. Quality Control Program for effluent monitoring, using the guidance j in Regulatory Guide 1.21, Revision 1, June 1974.
! j. Quality Control Program for environmental monitoring using the guidance in Regulatory Guide 4.1, Revision 1, April 1975. l ! 6.8.2 Each procedure of Specification 6.8.la through 1. above, and changes 2 thereto, shall be reviewed by the FRG and shall be approved by the Plant
- General Manager prior to implementation and shall be reviewed periodic
- .11y as l l set forth in administrative procedures.
i 6.8.3 Temporary changes to procedures of Specification 6.8 la through 1.
- above may be made provided
- a. The intent of the original procedure is not altered.
- b. The change is approved by two members of the plant management staff,
- at least one of whom holds a Senior Reactor Operator's License on
! the unit affected.
ST. LUCIE - UNIT 1 6-13 Amendment No. 25,50,00,02,107, 126 i
_ _ _ _ _ _ . . _ _ _ . _ _ _ _ _ _ _ _ . . _. _ . . _ _ . _. _ . ~ . _ _ _ _ _ .. . _ _ . _ . M i-j.* i ENFORCEMENT ACTION WORKSHEET I Failure to Maintain Overtime Mithin Guidelines h868 PREPARED BY: Mark S. Miller DATE: 7/3/96 { l NOTE: The seetten Chief of the roepensible Division le responelMe for properation of thle EAli erul its 4 distribution to attendees prior to en Enferoement Penet. The testien Ehlef theLL rtee he roepensiMe for ' i providire the meeting toestien and telephone bridge resber to ettendees wie e-arti (ENF.GRP, CFE, ameAIL, i ! JEL, JAG, SNL, LPD; appropriate All DAP, DR$; appropriate NAS, 18488:. A tietlee of Vietetion (without
=heiterptetea ) telah inetudes the reeammended severity levet for the vietetten le required. Caples of i 1 emptiemble Teshniest spe".sfisettene er License sanditlene sited in the metice er other referense motoriet f i needed t. evetuste the proposed enf.reement setten are reired t. he enetee.d.
i This Notice has been. reviewed by the Branch Chief or Div on Director and each violation includes the appropriate le e f speci as to how and when the requirement was violated. . 51gyturv i Facility: St. Lucia i Unit (s):-1 1 2 i Docket Nos: 50-335, 50-389 i License Nos: DPR-67, NPF-16 i Inspection Report No: 96-09 ! Inspection Dates: June 9 - July 6, 1996 Lead Inspector: Mark Miller i
- 1. Brief Summiary of Inspection Findings: A review of overtime over a one month period indicated that 56 individual deviations from TS required overtime guidelines occurred. The deviation: were not approved by plant management, as required by TS. The deviations were committed by 5 individuals. The number of examples of the proposed violation indicates particularly poor perforuance by the licensee in this area.
p$j,f$ - N O T ks< 7*0sa<r;z. W00/s19 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE h
'}
- 2. Analysis of Root Cause: Failure, on the part of tha individuals i
involved, to recognize the need for approved deviation requests, i failures, on the part of plant management, to conduct effective reviews l of overtime usage. With regard to the differences between gate logs and timesheets,
- comments were also received indicating that, while management had stated I 4
that overtime guidelines should not be exceeded, an unexpressed pressure I ! was perceived to meet outage schedules which led to work performed "off i i the clock." Additional comments were received which indicated that all 1
- of the parties interviewed were motivated by a desire to see jobs i through to completion, with several stating that their own expectations for their performance factored into decisions to work extra hours.
! 3. Basis for Severity Level (Safety Significance): No operational event or i . challenge to a safety system has been identified as a result of the violation identified. This is proposed as a SL IV violation, Supplement l I, D.3, a failure to meet regulatory requirements that have more than j minor safety. significance.
- 4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?
I i EA 96-249 10 CFR 50.59 Deficiencies, Supplement 1, 7/96, (pending) l EA 96-236 Configuration Management Programmatic Breakdown, Supplement
- 1, 7/96 (pending)
EA 96-040 Boron Overdilution Event, Supplement 1, 1/22/96 i j EA 95-180 Inoperable PORVs due to Inadequate PMT, Supplement 1, 8/4/95'
- 5. Identification credit? No I l Consider following and discuss if applicable below:
O Licensee-identified O Revealed through event O NRC-identified O Mixed identification O Missed opportunities Enter date Licensee was aware of issues requiring corrective actions: 6/6/96 1 Explain application of identified credit, who and how identified and consideration of missed opportunities: The issue of excessive overtime was identified by the licensee's QA organization in an audit conducted for the period of May 9 through 18. The NRC identified the issue in an audit conducted for the period of May 13 through June 13. The NRC was unaware of the licensee's audit. On ! June 6, QA discussed the issue with the Plant General Manager (PGM). Consequently, the Site VP and the PGM stressed personal accountability to their staff at morning meetings. Notwithstanding the licensee's immediate corrective actions, the NRC inspection identified 23 examples of unapproved deviations from the overtime guidelines in the time period from June-7 through 13. While the licensee's QA organization was able to identify cases of excessive overtime, the licensee's program for controlling overtime usage was ineffective in identifying the issue sooner. By procedure, the licensee's management was to perform monthly reviews of overtime PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
.___________.__.._._.___._____._____...__.y l l 4
i
- i. usage. The procedure failed to specify which managers were responsible i
for the required reviews or how the reviews were to be conducted. Consequently, opportunities to identify the problem were missed. J - l y 6. Corrective Action credit? Yes Brief summary of corrective actions: I
- Site VP and PGM discussed the problem with their staff at morning j meetings stressing expectations for personal accountability in !
this area. i e PGM issued letter to department heads on June 19 restating l guidelines and restressing personal accountability and the l possibility for discipline for violation of the policy. j
- The Site Services Manager proposed a monthly spot check of high overtime users, comparing time sheet totals to gate logs.
- The site VP explained to site management at a morning meeting, and later reiterated to the SRI, that it is his expectation that personnel working beyond guidelines receive prior approval, receive direct management oversight to ensure that fatigue does not impede the employee's abilities to work safely, and that employees working excessive hours receive a ride home and that someone else drive the employee's car home.
- QA has subsequently performed an audit of overtime use in the I&C department (the group showing the most examples of the inspector's violation) and has found no deficiencies, indicating that corrective action has been effective in the short term.
- Explain application of corrective action credit:
The licensee's actions to date appear to have reestablished control over overtime usage.
- 7. Candidate For Discretion? [See attached list) tsmer v or men Explain' basis for discretion consideration:
- 8. Is A Predecisional Enforcement Conference Necessary? No Why:
Severity of violation does not warrant conference. Additionally, no new information is predicted to be obtained.. l If yes, should OE or OGC attend? [ Enter Yes or No): J Should conference be closed? [ Enter Yes or No):
- 9. Non-Routine Issues / Additional Information: ;
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
- 10. This Action is Consistent With the Following Acticn (or Enf rcement
- Guidance) Previously Issued: trics t prwies rif ine.n.t.t.nt. inctum:3 Basis for Inconsistency With Previously Issued Actions (Guidance)
- 11. Regulatory Message:
A strong commitment to maintaining overtime usage at acceptable levels is necessary to minimize the potential for human error which might result in challenges to safety.
- 12. Recommended Enforcement Action:
SL IV
- 13. This case Meets the criteria for a Delegated Case. trics enter v .c m.:
- 14. Should This Action Be Sent to OE For Full Review? crics ent.r v or m.
If yes why:
- 15. Regional Counsel Review inics to et ina No Legal Objection Dated:
- 16. Exempt from Timeliness: reicsi Basis for Exemption:
Enforcement Coordinator: DATE: PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
l ENFORCEMENT ACTION NORKSHEET - ISSUES TO CONSIDER FOR DISCRETION O Problems categorized at Severity Level I or II. ! O Case involves overexposure or release of radiological material in excess
- of NRC requirements.
i I
- O case involves particularly poor licensee performance.
1 ! 0 Case (may) involve wi11 fulness. Information should be included to 4 i address whether or not the region has had discussions with OI regarding l 1 the case, wnether or not the matter has been formally referred to 01, i
.and whether or not OI intends to initiate an investigation. A I
i description, as applicable, of the facts and circumstances that address
- the aspects of negligence, careless disregard, willfulness, and/or '
management involvement should also be included. j i ' i O current violation is directly repetitive of an earlier violation. J I i . O Excessive duration of a problem resulted in a substantial increase in l l risk. ] ! O Licensee made a conscious decision to be in noncompliance in order to obtain an economic benefit. j O Cases involves the loss of a source. (Note whether the licensee self- ! identified and reported the loss to the NRC.)
- f. O Licensee's sustained performance has been particularly good.
O Discretion should be exercised by escalating or mitigating to ensure i that the proposed civil penalty reflects the NRC's concern regarding the violation at issue and that it conveys the appropriate message to the licensee. Explain, r. i l 1 l h I-l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
1 Enclosure 3 i . REFERENCE DOCUMENT CHECKLIST d [x] NRC Inspection Report or other documentation of the case: j NRC Inspection Report Nos.: IR 96-09 4 [x] Licensee reports: Quality Assurance Audit QSL-PM-96-08 l~ i [x] Applicable Tech Specs along with bases: [] Applicable license conditions ! [x] Applicable lic ~se procedures or extracts AP-0010119 Rev. 14 [x] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results Typical time sheet ) [] Extracts of pertinent FSAR or Updated FSAR sections for citations , involving 10 CFR 50.59 or systems operability l [] Referenced ORDERS or Confirmation of Action Letters [] Current SALP report summary and applicable report sections
- [] Other miscellaneous documents (List)
i i l .i ) 1 4 [ PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE
4 2 4 4 I i 4 1 i !. Excerpt From St. Lucie Inspection Report IR 96-09 i 4 i l i L, k l l
08.X Control of Overtime The inspector reviewed the licensee's control of overtime for the period of May 13 through June 13. The inspector obtained gate logs for.26 individuals.. The selected individuals were chosen from the licensee's maintenance, engineering, planning, and management organizations based upon their involvement in outage activities and the inspector's understanding of the activities under their cognizance. From the results obtained (which demonstrated time spent on site), the inspector reduced the inspection population to five individuals based upon indications of excessive hours. The individuals in question included supervisors and engineers with responsibilities for-safety-related work. As acceptance criteria, the inspector reviewed TS 6.2.f, which required that the hours expended by personnel performing safety-related functions be limited, with an objective that personnel work a normal 8 hour day, 40 hour week while the plant was operating. The TS observed that substantial amounts of overtime might be required during extended
-periods of shutdown for refueling, and established guidelines for these l periods. The TS stated"
...on a temporary basis the following guidelines shall be followed:
- a. An individual should not be permitted to work more than 16 hours straight, excluding shift turnover time.
! b. An individual should not be permitted to work more than 16 hours 1 in any 24 hour period, nor more than 24 hours in any 48 hour period, nor more than 72 hours in any 7-day period, all excluding i shift turnover time. $ c. A break of at least 8 hours should be allowed between work
- periods, including shift turnover time...
~
...Any deviations from the above guidelines shall be authorized by the l Plant General Manager or his deputy, or higher levels of management, in l
, accordance with established plant procedures and with documentation of t the basis for the deviation." The inspector reviewed AP 0010119, revision 14, " Overtime Limitations for Plant Personnel," and found that the procedure appropriately implemented the TS requirements.
- The inspector found that the licensee deviated from TS guidelines for 5
the control of overtime without the prior (or subsequent) approval from senior plant aanagement. Of the five individuals focused on as a result 4 i of gate logt,, the following information was obtained from timesheets (violations of the requirements were cited only for excesses of requirements which had not received approval per AP 0010119): 1 Individual Violations of 72 Violations of Violations of 16 Hour Requirement 24/48 Hour Hour Requirement J Requirement
- A 3 0 0 i
PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE
l B 0 0 0 i C 5 1 0 D 14 2 0 I E 16 12 3 . 1-l Total 38 15 3 4 The instances identified above, in which TS guidelines were exceeded, and for l which the TS-required approvals for the deviations were not obtained, ! collectively represent a violation (VIO 96-09-XX, " Failure to Control l Overt 5 "). f While violations were identified, the inspector also noted that significant differences existed between timesheet records, which divided time between TS ! and non-TS categories, and gate records, which indicated total time on site. ! For the 5 individuals highlighted above, numerous instances of differences ! between total time on site and timesheet-indicated time on site existed, with ! differences frecuently exceeding one and two hours and, at times, exceeding i several hours. The most time spent continuously on site was noted to be
- approximately 26 hours, h The inspector discussed the results above-with the affected parties to j ascertain the reasons for the excessive use of avertime and for the differences between gate logs and timesheets. Responses were mixed.
l Regarding the heavy use of overtime, severe 1 respondents pointed out that the , project that they.had been working was adversely affected by the loss of l l several key personnel (one to layoffs, one to death, and one to termination I i for cause), which reduced the depth of knowledge on the associated job. ! Several stated that the diverse activities on both units (due to the outage on l Unit I and the recent trip of Unit 2) had placed increased demands on their i time. I I i In discussing the method for completing timesheets, the inspector found that a lack of uniformity existed. Some respondents treated work periods (as
- described on the timesheet) as any work performed on a given calendar day. By l applying this approach, the potential existed for the work hours recorded for a given day to represent a composite value of two work periods if one (or more) of the work periods extended across midnight. The potential result of this type of accounting was that the true length of a work period, as referenced in TS, would not be accurately reflected on timesheets, confounding .
the ability to maintain an accurate count of daily, 48 hour and 7-day totals. I With regard to not obtaining the appropriate deviation approvals for time worked in excess of the guidelines, several workers stated that they believed that obtaining a deviation provided a blanket authorization for overtime spent on the project for which the deviation applied. ~The inspector noted that the AP was not specific as to whether a deviation request was required for each planned deviation from the guidelines or whether it applied to the job which was described on the request. The inspector discussed this issue with the Plant General Manager, who stated that it was his expectation that a deviation request be filed for each planned deviation of the guidelines (the implication being that t. series of work periods for which each period led to violations of PROPOSED ENFORCEMENT ACTION - NOT FOR PUSUC DISC 1.OSURE WITHOUT THE APPROVA1. OF THE DIRECTOR. OE
.one or more guidelines should each be documented on separate requests). The
- inspector had requested any deviation requests associated with the personnel l
audited for the subject time period. Two were identified which addressed t ] themselves to 3 of the personnel. The deviations covered by these deviation . 2 requests were not considered in the summary table above. { AP 0010119 required that department heads perform a monthly review of assigned 1 overtime to assure that excessive overtime was not assigned. The inspector ! questioned the licensee as to how those reviews were executed..... I Independent of this inspection (and unknown by the inspector), the licensee's j QA organization performed an audit of overtime usage for the period from May 5 l through 18. A population of 100 plant personnel was selected at random for
- the audit. QA reviewed gate logs for the sample population and applied i criteria which assumed a one half hour lunch break and accepted turnover
! periods to reach the following criteria for determining whether guidelines had l been exceeded: }
- No more than 17.5 hours in 1 day.
!
- No more than 27 hours in a 48 hour period l
- No more than 82.5 hours in a 7 day period i . An 8 hour break between work periods.
QA determined that 13% of their population exceeded the criteria at least once ! and that 8% exceeded the criteria at least twice. QA informed management of l their findings in this area on June 6. As a result, the Site Vice President 4 and the PGM discussed the problem with plant staff at morning meetings to ! stress expectations for personal accountability in this area. On June 19, the PGM issued a letM r to department heads restating the overtime guidelines and i stressing personal accountability on the issue. The inspector noted that,
- with respect to immediate corrective actions, 23 examples of unapproved j deviations existed in the inspector's sample from June 8 through 13.
j As a result of this inspection, the inspector concluded the following: !
- Overtime usage for the period May 13 through June 13 has exceeded TS
! guidelines for a number of personnel. i !
- The licensee failed to effectively control overtime as' required in AP i
0010119, revision 14, " Overtime Limitations for Plant Personnel," in
- that deviation requests were neither prepared nor approved for the l
majority of deviations identified.
- AP 0010119 was unclear in its expectations, both for when a deviation
! request was required and for who was responsible for reviews of overtime usage (and how it was to be executed), i j -
- The requirement for monthly reviews of overtime usage, detailed in AP 0010119, was ineffectively implemented.
!
- Personnel have, at times, worked hours which were not recorded on i timesheets.
i ! PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE h e
J. - PREDECISIONAL DRAFT INFORMATION - NOT FOR DISTRIBUTION NOTICE OF VIOLATION 4 Florida Power & Light Company Docket Nos. 50-335 and 50-389 l St. Lucie 1 and 2 License Nos. DPR-67 and NPF-16 .
- i. \
l During an NRC' inspection conducted on June 9 through July 6, 1996, violations
- of NRC requirements were identified. In accordance with the " General
! Statement of Policy and Procedure for NRC Enforcement Actions," (60 FR 34381; - j . June 30, 1995), the violations are listed below: ! A. Technical Specification 6.2.f, requires that the hours expended by j personnel performing safety-related functions be limited and that during i extended periods of shutdown for refueling, the following guidelines be i observed:
- a. An individual should not be permitted to work more than 16 hours
{ straight, excluding shift turnover time. ! b. An individual should not be permitted to w3rk more than 16 hours j in any 24 hour period, nor more than U. f.ours in any 48 hour period, nor more than 72 hours in any 7-day period, all excluding j- shift turnover time. i ! The Specification further required that any deviations from the above
- guidelines be authorized by the Plant General Manager or his deputy, or j higher levels of management, in accordance with established plant j procedures and with documentation of the basis for the deviation. AP 0010119, revision 14, " Overtime Limitations for Plant Personnel,"
i implemented this requirement and provided an administrative vehicle for , ! the approval of deviations from the specified guidelines. )
- l
! Contrary to the above, during the period from May 13 through June 14, I i 1996,'five individuals who performed safety related functions were found l j to have contributed to 38 deviations from the 72-hour-in-any-seven-day-i period requirement, 15 deviations from the 24-hour-in-any-48-hour
- requirement, and 3 deviations from the 16-hour-in-any-24-hour-1 requirement without obtaining authorization from the Plant General i Manager, his deputy, or higher levels of management.
C : \br51 \DOQAIEN T \SNELL \RPT SE LA.lr neport print.d 9:35 ==, Frid y. Juty 19,19m 10
l s .l - l I i 4 i J Quality Assurance Audit QSL-FM-96-08 4 4 e 4 5 4 l. t - .v' a i e i 1 , 1 i ? l i J i J f I k i 1 e 4 0 6 1 ( i 4 i A a l d
27-19-1996 05:03AM St Lucio Reattent OHie? 407 461 162? P.02 k Inter-OITice Correspondence l
\
FPL I JQQ-96-086 To: J. Scarola Date: July 8,1996 From: L. W. Bladow Department: JNA/PSL
Subject:
Quality Assurance Audit OSL-FM-96-08 ,
'2 Attached is a summary report for QA Performance Monitoring activities completed during May/ June,1996 to assess the implementation of the Quality Assurance Progrcm at St. Lucie.
The following three findings are documented in this report and have been discussed with appropriate personnel and exited with PSL Plant Management. Findine 1: Inadequate Procedures for Resio Transfer A. The procedure an'd methods in use during blowdown building resin transfer did not im,a l ' the system operating description for Blowdown Building resin discharge as found in the FSAR. B. The procedures used to changcout typically non-radioactive resins do not provide adequate , radiological controls when the resins are radioactive. C. The procedures in use during a Blowdown Building resin transfer were not being completely follow:d in that several radiologi:a! controls were not in place. Findinc 2: Procedure Non-compliances with Requirements for Control of Breathing Air Stations contrary to requirements, HP Techs provided bubble hood respiratory protection with air alpply pressures that execcded procedure limits. Neither procedure HP-61 or a usable Table ! of that l procedure were available. BA station BB 029 calibration data posted with the machine was not complete. Other stations (BB003 and BD004) were found with expired calibration stickers and incomplete calibration sheets. Findine 3r Violation of Overtime Guidelines A. During the period 5 through 18 May 96,12% of the sampled popula: ion exceeded cne or more of the overtime guideliner.. B. Overtime deviation requests are net being fiHed out and forwarded to the vault as required. C. Management reviews of overtime guideline adherence are ineffective.
O'7-19-19 % 05 gmM St Luc e Re omt Offica 622 P.E Q' Cd
. I AUDIT REPORT Ek-QStrPM-96-08 Page 12 of 28 i /
1 observed to be conducted per established procedural guidelines. Upon satisfactory completion of the PMT per Data Sheet C, QA monitored the performance of the flow tests of the 2C AFW Pump its valves per Data Sheet D. Activities were accomplished per procedure with satisfactory results. - Performance Monitor: L. Panessa
, Services /Earineerinr/Other l PMON 96-033 was initiated to insure Plant ccmpliance with overtirne controls'specified in Technical Specifications 6.2.2.f and Administrative Procedure AP0010119, Rev.14. This evaluation was conducted by reviewing security; gate log entries and exits from the protected area for a random sampling ofpersonnel currently badged at the St. Lucic site. Selected personnel were drawn from a l
population of 16 plant departments and eight different contiactor companies all of which have the ' potential to perform safety related work activities. Individuals examined were selected using a random number generator. Interviews were conducted with management personnel to examine consistency in understanding a implementation.of overtime guidelines. Records of overtime deviation requests were reviewed. Interviews conducted indicate that managers and direct reports are reviewing time sheets each pay period to ensure compliance with overtime guidelines. In addition, personnel have been instructed to report in advance any anticipated overtime that would exceed the guidelines. Management , interviews revealed a consistent interpretation of the overtime limits . As currently implemented the l overtime policy allows turnover time of 30 minutes before and after each shift in addition to the maximum limits stated in the technical specifications. This understanding is contained in a maintenance memorandum datcJ 20 April 1992. Other than this Mechanical Maintenance memorandum, other plant wide guidance defining shift turnover time was not located during this audit. Consistent implementation of shift tumover time was not found when time records were reviewed. The target population contained 1,572 badged personnel. A sample size of 100, 6.4% of the population, was randomly selected. Security gatelogs were obtained for the period,5 through 18 May 96, inclusive. Allowing 30 minutes for a lunch break and applying the previously discussed dermition of shill turnover to the criteria in AP0010!!9. the following maximum thresholds for allowed hours on site were catablished:
- 1. No more than 17.5 hours in 24
- 1. N'o more than 27 hours in 48
- 1. No more than 82.5 hours in 7 days 1.
An 8 hour break exists between work penods (including snift turnover). d
t 1 . 1 Unit 2 Technical Specification 6.2 1 1 i l l l l l
P.[ ~ ~ O'-19-1996 04855AM St Lucne Res: dant Off1ce : 4Er7 4614622 i dif7 4614622 P.82
.~
- 06-19-1996 1183e8N . et Luc e Residxnt Office es.. = - 2-. l ADMINISTRATIVE ... CorTROLS_ _ _.
- .... e ..:
6.2 ansANIZAff0N(Continued) Eli.20EI-6.2.2 The unit organization shall be subject to the following:
- a. Each on duty shift shall be composed of.at least the minimum shift crew sosposition shown in Table 6.2-1.
- b. At least one licensed Reactor Operator shall be in the control room when fuel is in the reactor. In addition, while the reactor is in MODE 1, 2, 3, or 4, at least one licensed senior Reactor Operater shall be in the control room.
- c. A health physics technict2nd shall be on site uhen fuel is is the reactor.
l
- d. All CORE ALTERATIONS shall be observed by 4 licensed operator and l supervised by either a licensed Senior Reactor Operator or Senior Reactor Ooerator Limited to Fuel Handling who has no other concurrent responsibilities during this operation. The SRO in charge of fuel handling normally supervises free the control room and has the flex 1 bility to directly supervise at either the refueling deck or the '
spent fuel pool.
- e. DELETED f.
Administrative procedures shall be developed and implemented to limit the working hours of unit staff who perfore safety-rel nad functions;.e.g., senior reacter operators, reactor operators, health physicists, auxiliary operators, and key maintenance personnel. Adequate shift coverage shall be maintained without routine heavy use of overtime. The objective shall be to have operating personnel work a normal 6 hour day, 40-hour week while the plant is operating. However, in the event that unforeseen paeblems require substantial amounts of overtime to be used, or during extended periods of shutdeun for refueling, major saintenance or major plant modification, on a temporary basis the following guidelines shall be fellowed: s i'
#The health physics technician may be less than the minimum requirement for a period of time not to exceed 2 hours, in order to accommodate ,
unexoected absence. provided immediate action is taken to fill the required positions.
- 37. LUCIE - UNIT 2 6-2 W No. 49 55
07-19-1996 04:55AM St Lucie Ressoznt OHica 1 407 461 46Z2 ~~ W^~ P i der / 4614522 P.53 EE-10-1996 ill39R1 5t Lucie neeident OHice
, Afs4fNtSTRATIVE CuniiGLE WIT STAFE (Continued)
- a. An individual should not be permitted to work more than 16 hours straight, excluding shift turnover time,
- b. An individual should not be permitted to work more than
,16 hours in any 24-hour period, nor more than 24 hours in any 48-hour period, nor more than 72 hours in any 7-day period, all excluding shift turnover time.
- c. A break of at least 4 hours shosid be allowed between work periods, including shift turnover time.
l
- d. Except dering extended shutdown periods, the use of overtime i'
should be considered on an individual basis and not for the entire staff on a shift. Any deviation from the above guidelines shall be authorized by the Plant General Manager or his deputy, or higher levels of management, in accordance with established procedures and with documentation of t w basis for granting the daviation. Controls shall be included in the procedures such that individual overtime shall be reviewed monthly by the Plant General Manager or , his designee to assure that excessive hours have not been assigned. Routine deviation from the above guidelines is not authorized. I l
- g. The Operations Supervisor shall hold a senior Reactor Operator License.
l l l l l : I I I t l ST. LVCIE - UNIT 2 6-ta Amendment No. 39.65 l l l t - -- . .
4
,4 1
i ( 3 I a t 5 I J 4 J r i, St. Lucie Administrative Procedure No. 0010119 f i i i i I I i 1 ) i 4 l 1 l l ( i I' 1 1 + l i l l, 1 t i e i i i, 4 4 4 i J
_. - . . - . - _ . . . . . . - - . . - . - - . - - - - . - . . . . . - - . - ~ . - . _ - . - - - - - . . 0?-19-1996 04:56Ar1 St Lucie Ressesnt Offace 407 461 4622 P.05
- a.
- 06-16-1996 11:39m St Lucie Reatd:nt Office 1 487 461 4622 P.84 Fags 1 of G FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010119 -
~
REVISION 14 r 1.0 IID.E: ' OVERTIME LIMITATION 8 FOR PLANT PERSONNEL L-2.0 REVIEW AND APPROVAL: Reviewed by Facility Review Group 10f31 19,3,,, Approved by J. H. Barrow (for) Plant General Manager ' 10/31 19,gD_ l Revision 14 Reviewed by F R G 5/519,36,,, l Approved by C. L. Burton Plant General!4anager S/B 19,g,4,,,, l
3.0 SCOPE
3.1 This procedure pmvides administrative requirements and doeurnentation l requirements for plant personnel working. overtime.cn. safety.raistadJunctions. , , FOR INFORMATION ONLY l l
4.0 PRECAUTIONS
THis oocumur :s wo: comtou.to, serone uu, . i VERFY INFORMATION WiTH A CONTRou.ED DOCUMENT. j . None stOatoApown ANeucxt co.sT.LUCIE PLANT l
5.0 RESPONSIBILITIES
r oAnveneno ! mmAts 5.1 The Plant General Manager is responsitlFie for ensuring that the use of overtime is minimized. 52 Each department head is respor E,le to provide necessary work schedules without routine heavy use of overtime. l 5.3 Each department head is responsible to follow these instructio.w and ensure documentation of the basis for use of overtime exosoding the guidelines. 5.4 The Adrninistrative Department is responsible 'er maintaining updated copies of th. piant rost.r in .ach Cm Room. , s, ors DATE DOCT P8WQEDURE INFORMATION ONLY ="""' COMP COMP 1.ETED l ITM 14 l
09-19-1996 04:56AM St Lucts k agesnt Office 1 407 461 4622 P.06 {** ' 06-le-1996 11:402'l St Lucie beident Offico 1 487 461 4622 P.05 Page 2 of 5 ST. LUCIE PLANT 1 ADMINISTRATIVE PROCEDURE NO. 0010119, REVISION 14
- OVERTIME LIMITATIONS FOR PLANT PERSONNEL l 6.0 REEEEIENCES
- ,
- 6.1 Tech Spec Section 6.2.2.f 6.2 NUREG 0737 Section I.A.1.3 6.3 Administrative Procedure 0010518, " Fitness for Duty Call Out and For Cause Testing."
6.4 Nuclear Policy NP 306, Overtime. . 6.5 St. Lucie Plant Policy, PSL-202, Overtime. /R14 7.0 RECORDS AND NOTIFICATIONS: 7.1 Completed Overtime Deviation Requests shall be maintained in the plant files in accordance with Ol 17-PR/PSL 1, " Quality Assurance Records'. INFORMATiON ONI.Y
i 07-19-1996 04:56AM St Lucie Residsnt OHics 1 407 461 4622 P.Er? j a. t 86-le-1996 11:40R1 St Lucie Re::1dsnt OHice 1 derr 4614622 P.es Page 3 of 5 l ST. LUCIE PLANT l ADMINISTRATIVE PROCEDURE NO. 0010119, REVISION 14 i OVERT 1ME LIMITA'nONS FOR PLANT PERSONNEL i I 8.0 INSTRUCTIONS: . i l 8.1 Excesolve utilization of overtime is counterproductive and is to be avoided. 8.2 The nuoiser plant personnel in all departments shaN be covered by these ! Instructions. /R14
/R14 l
1 . NOTE i Nuclear Division personnel should adhere to these limits. Variations from j these limits can only be authonzod by the Vios Prooident - St. Lucie Plant or i his designee in accordance with the requirements of Nucisar Policy NP 308, t Overtime. I 1 i 4 8.3 Overtime Limit Guidelines: l i
- 1. An indhridual should not be permitted te work more than 16 hours straight, emoluding shift tumover time.
t ) i 4 2. An individual should not be permitted to work more than 16 house in any i 24 hour period, nor more than 24 houra in any AS hour period, nor more 1 than 72 hours in any 7 day period, all excluding ohlft tumover time. An
- ecceptable deviation to this guideline is the STA seven consecutive )
- 12 hour shift schedule. l l-
! 3. A break of at least 8 hours should be allowed between work perioda, , j moluding shift tumover time.
- 4. Except during extended shutdown penode, the use of overtime should be i
considered on an indiv6 dual basis and not for the entire staff on a shift. j 8.4 Deviations from Overtime Limit Guidelines: i 1. Deviation from the overtime guide'ines shall be approved by the Vice { President - St. Lucie Plant, Plant General Manager, Services Manager.
- 2. The senior person on sits from their respective department shal complete the overtims deviation request (Figure 1) and obtain the necessary 4
approval for personnel specifically outlined in sooten 8.2 of this procedure. AR St. Lucie Plant personnel shall comply wrth Nuclear Poley . Guideline NP-306, Overtime,
- INFORMATiON ONLY j
4 I s i Typical Copy of Discrepant Time Sheet i l 1 t 4 2 i , 3 p
- 07-19-1996 04
- 54AM St Lucie Residznt OHice 1 407 461 4622 P.82
- v. a <
, s .
? eer wunemes esemensmeu I
wam me Nep0ft No. een esieena sesues an . l l *uwe==*ssenas= sumume tavt one smaasse enum d was taas M sensen ._ te0 t ActsmontS eX1 .-
.aaw '- ** *ni *** = i.
j soe u m - nwa . 04 07 94
;4 . o+et 1
' en e* an en -
i onen _e e. sean vswa a.c= eMn e *w see anan invie asume ew .mo ram esm, vgyTAL 4 f oav ee vus asess i=e ese 25 2e 27 rs 2s M s1 01 02 03 04 09 04 01 secuns , M l a, et 0.0 7.0 JAI / .0)2 7.0 7.0 7.0 7.0 7.0 7.0 #0 /, u,0 j '**= 02 8.00 II.3 Y 8.0
*=== es P som, i
, I
=== 0* so a l 42 i
4 3.0 ll 4 . O "" is 1.0 1.0 1.0 l 1.0 1.0 1.0 1.0 1.0
.ns
! l em to
- ase e ;
J me .ma j p. essina 12 esmia s a ew w tA N sinnen j u 14.0 13.2 14.0 6.0 'd
. 3.2 12.0 l 12.0 ' 3.0 2.0 5.5 1 7.0 5.5 g010 3.1 /
,g l ~ Z '*"I M \
t ,
,s .w ,,rna e4 su ou is e 's.: a.e su ins is o ie s e4 e s.. ies is.i 183.0 "'0,l" et names asas eesssas 1 1 i i 1 1 i i 1}}