ML20140E659

Provides Revs of Plant Violations for Current Hour

ML20140E659
Person / Time
Site:	Saint Lucie
Issue date:	11/12/1996
From:	Kreh J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	Boland A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
Shared Package
ML20140E502	List: ML20140E497 ML20140E508 ML20140E514 ML20140E519 ML20140E524 ML20140E530 ML20140E536 ML20140E541 ML20140E557 ML20140E573 ML20140E580 ML20140E590 ML20140E594 ML20140E620 ML20140E652 ML20140E659 ML20140E667
References
FOIA-96-485 NUDOCS 9704290082
Download: ML20140E659 (356)

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From: James Kreh dT2_c. : A-2 To: ATB Anne,# bled , dR4. lR7-Date: 11/12/96 2:46pm

Subject:

ST. LUCIE VIOLATIONS Here are the revisions for the current hour. I've gone beyond what we discussed on items 1 and 3 - please scrutinize carefully.

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9704290082 970423 PDR FOIA PDR l BINDER 96-485

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DRAFT NOTICE OF VIOLATION REVISED 11/12/96 St. Lucie 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 i General Emergency, and that arrangements have been made to staff the TSC l and OSC in a timely manner. Also s Emergency Operations Facility (EOF)pecified is that is required for activation a Site Area of the 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-l 3100023E, "On-Site Emergency Organization and Call Directory"',

i Revision 72. The instruction in Section 8.2 of that procedure states that, upon the declaration of an emergency classification, "the Duty

-Call Supervisor will initiate staff augmentation" using the _" Emergency Recall System or A notify persons..."ppendix A Duty Call Supervisor Call Directory to Contrary to the above, from approximately July 22 to October 3.'1996, j 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 Recall l System) or the backup method (using the Duty Call Supervisor Call i

-Directory) for notifying its personnel to report to the plant during l off-hours to staff and activate the TSC, OSC, and EOF.

This is a Severity Level IV violation (Supplement VIII).

! 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 l 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

[ER0] Personnel", states, "The training program for members of the on- i 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... For g employees with specific assignments or authorities as members of emeroency teams, initial training and annual retraining programs will be provided. Training must be current to be maintained on the site Emergency Team Roster." REP Section 7.3.2 states, "The Plant Training

Manager will ensure that on-site Emergency Response Organization personnel are informed of relevant changes in the Emergency Plan and i Emergency Plan Implementing Procedures [EPIPs]."

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! Contrary to the'above, the licensee failed to adequately implement its training plan for ERO personnel as follows:

1. Since at least 1994, the training provided to most members of the

, on-site ERO did not include practical drills and participation in -

exercises.

2. In 1994, the licensee failed to provide initial training or annual

retraining for 17 positions (approximately 92 individuals)

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identified as part of the on-site response organization. In 1995, i the licensee failed to provide initial training or annual '

retraining for 8 positions (approximately 54 individuals)

- identified as part of the on-site response organization.

3. The licensee's training program. failed to-include ~ initial or 1

3eriodic retraining on all procedures required to be implemented ay ERO personnel in several identified Jositions. The Plant i Training Manager failed to ensure that ERO personnel in several identified positions were informed of relevant changes in

-)rocedures EPIP-3100026E, " Criteria for and Conduct of Evacuations": EPIP-3100027E. "Re-entry"; and EPIP-3100035E, "Offsite Radiological Monitoring".

4. For the calendar year 1995, the licensee failed to remove from the emergency response organization 4 individuals who had not completed retraining as required, and whose qualifications had expired in 1994. The licensee also failed to remove 6 individuals from the emergency team roster effective October 6, 1996, who had not remained qualified to fill response team requirements as a result of allowing their respirator qualifications to lapse.

This is a Severity Level IV violation (Supplement VIII).

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NRC CLOSED PREDECISIONAL ENFORCEMENT CONFERENCE ST LUCIE NUCLEAR PLANT I

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MARCH 8,1996  !

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NRC CLOSED PREDECISIONAL ENFORCEMENT CONFERENCE ST LUCIE NUCLEAR PLANT MARCH 8,1996 IAH TITLE 1

Predecisional Enforcement Conference Agenda 2 Expected Attendees, Meeting Announcement 3 Opening Remarks and introductions 4 NRC Enforcement Policy 3 5 Summary of the issues 6 Statement of Concerns / Apparent Violations ,

7 Inspection Report No. 50-335,389/96-03  !

8 , Unit 1 Control Room Arrangement, CVCS Charging System Flow Dieg.am, l

Enforcement Pre-Panel Questionnaire l 9 Licensee Procedure OP 1-0250020, Boron Concentration Control - Normal Operation;  !

and TC 1-96-017 to OP 1-0250020 of 1/23/96 10 Licensee Procedure Ql5-PR/PSL-1, Preparation, Revision, Review / Approval of Procedures I 11 Licensee Procedure AP 0010120, Conduct of Operations; and TC 0-96-014 to AP 0010120 of 1/29/96 p/l-b; d a way N$e.] O ,b F'%

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r 12 Memo from E. Jordan on Licensed Power Level of 8/22/80 13 St. Lucie Unit 1 FSAR 14 Closing Remarks pgse.d'in& h S91 h#f g qyr/0(h}N M r* *"4

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{ March 6,1998 U. 8. Nuclear Ro9ulatory Commission

! Attn: Document Cordrol Desk l Washington, DC 20566 1 Re: St. Lucie Units i and 2 l Docket Nos. 60436 and 60-389 i Escoes Dilution of the Reactor Coolant System Due to Personnel Error i Nunlaar Problem Raoort 96 008. Raylalon.1 i

4 As the result of an event involving the excess dilution of the Reactor Coolant System at j St. Lucie Unit i on January 12,1996, Florida Power & Light Company (FPL) Initiated a

! oross4unctional investigation to determine root cause and corrective actions. On February 21, 1996, en interim Nuclear Problem Report '(NP) 91W08 was issued discussing l preliminary conclusions.

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' The purpose of this letter is to forward to the NRC Revision i to NP SS 008 which, in addition to presenting the results of the original cross-functional investigation concerning i root cause and corrective actions, includes the event analysis and conclusions of an j indept.ndent, non-FPL expert on nucicer plant operations and event analysis.

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N you have questions on the attached repot t, please contact us.

Vice Prealdent i St. Lucie Plant i

l Attachment i

i WHS/EJW i

j oc: Stewart D. Ebncier, Regional Administrator, Region ll, USNRC, Atlanta, GA

Senior Resident inspector, USNRC, St. Lucie Plant i

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} gT.LUCIEPLANT NP.700 PROBLDE REPORT 96-048 l .

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} L EVENT TITLE Emoons Dilution of the Reactor Coolant Symem Due to Personnel Error.

l l St.Lucie Unit 1 Event Date: 22 Jesuary,1996 i

INITIAL PLANT CONDITIONg i l ]L

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l l Unit I was at 100 percent power, steady state operations EL EVENTREOUENCE l

At approximately 0220 on January 22,1996 normal reactor fbal depletion resulted in an 1 j insBcated reactor coolant cold leg temperature (T,) of 548.7F. The Board Reactor Control Operator (BRCO) commenced a dilution to the Reactor Coolant System (RCS)in order to restore T. to a temperature of $48.9F. He began a manual dilution with Primary Mahoup Water (PMW) at approximately 38 gym directed to the auction of the IB Charging Pump at 1

] approuirnately 0225. According to the BRCO, ahortly after the dikalan was comrnanced l ====alaw E-9, " Lube Water Supply Strainer d/p Hi", was received. The BRCO at the

[ eestrels ist the vidnity ofRTGB 105 (this is the location of the controls fbr the boration and i eution system) to acimowledge this alarm on RTGB 102. AAer responding to the alarm, the j

BRCO requested that the Desk RCO (DRCO) relieve him at the controls so he might go to  !

j the M aa 'Ihm DRCO moved into the vicinity ofRTOB-103. The dilution in progrees was not aa====Imad by the BRCO during the short term turnover process. The BRCO then

] let the "at the coetrols area' and went to the kitchen to prepare his meal, i 1

i An 4 etdy 8ve minutes later, the BRCO returned to the control room and heard the l PMW integrator "Abg". '!he BRCO realised the addition of primary makeup water to the RCs was stil in progress and immediately took corrective actions to seaare the dilution and conunenced borating the RCS. The BRCO commenced boration to the auction of the IB Charging Pump fbr a total initial addition of approximately 26 gallons of boric acid and intuned the DRCO and the Nuclear Plant Supervisor (NPS) ofhis actions. At approximately the mas time the BRCO was taking corrective action, annunciator M-16 "RCP CONT BIDOPP PRESS HIGH" alarmed, due to a higher than normal Volume Control Tank (VCT) ,

pressurs eom the increase in VCT level and Pressurizar level u a result of the expansion of '

RCg invensory from Tsve irseg. The Assistant Nuclear Plant Supervisor (ANPS) was

==== aged by the NPS to the control room from the khchen to assist in actions to return the plant to within nonnat operating parameters. T, was observed to be greater than 549F.

With the boration started, the NPS and STA reviewed the Technical Specifications and 1

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j IA641 Aussbasst Mank4.1996 Revison 1 entered a two hour notion atstement to restore RCS T, to less than or equal to $49F la l

essordanos with Technical Speci$cadon Limhing Condition of Operation (LCO) 3.2.5, DNR

! Parameters. At 0314, ladleated T was returned to less than 549F, and the LCO Action i stmemen we enhed. An other pannsters reached normal lsveis concurrently. As was later i

calculated, and sonarmed by morded piant indications, the hishest reactor power and acs i cold leg temperature during the event was 101.13 percent and $50.8F (single point l maximum),

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! Behre the crew let the site that morning, several reviews of the event began. The crew l shit shpervision verbally counseled the BRCO for leaving his station whue a dihaion was in i progrees. The ANPS also wrote a nodiention of the event in the form ofDeta Sheet (D8) j 7 (Operations M  ; Problem Report, Conduct of Cp h procedure) and mailed i a paper copy to the Operations Supervisor. He ANPS provided a verbal noti $ cation ofthe event to the Operations technical supervisor during his normal moming tour of the control rooms. The STA prepared a drat In Houes Event (IHE) summary 96008 to convey the & cts

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j of the event to the she managemet and to initiate a STAR ibt root cause determinatica. The 8TA also requested that the Human Peribnnanos Evaluation System (HPES) Coordinator be i called out to investigste the event. The HPES Coordinator arrived onsite at 0515, reviewed the dreA IHB and conducted interviews whh the personnel involved. At the 0740 morning .

management phone onll, the Operations Supervisor and the Plant General Manager were provided with a copy of the IHE. On that same day, the Operations technical supervisor began an event review which included dt-Was with the reliefcrew, RCO chronological j

review, the D5 7, training and performance appraisals related to the BRCO. At the end of j

the day, the W_== technical supervisor recommended to the Operations Supervisor that '

i the BRCO be removed tom watch standing duties. He also notified the NRC Resident of the i lavestigation status.

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j On the ibliowing day (January 23), the Operations technleal supervisor conducted a ikt finding meeting with the crew and bargaining unit represortative. Following that meeting, the j Opemtions Supervisor conouned in the suspension of the DRCO Som watch standing duties.

1 The Operations technical supervisor provided the NRC resident with an update to the event, j On January 26, the DE was updated by the HPES Coordinator to include all of the fhets

! lemmed about the event dudna the week. At the direction of the Plant General Manager, on i

January 31,1996, a cross ihnetional team was fbrmed to review the event and M::p l plant ataffrasponse, i

j IL ANALYBIE i

The team identi8ed two primary problems for this event. They are discussed in detail

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I i Manh6.1996 l i L9641 Revisina1

! Assessee FROBLEM 11 '

A reassivity evolution was initleted without adequate controls. '

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Routine boroa dilutions to maintain 100 percent power are not treated with the l

lanportance as other reactivity awagement evolutions. This is particularly i

and of coa lit when tequent arnall additions of primary water are Iglected in to the maintain 100 percent power.

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1) Cognidvs error on the part oitheBRCO who inidated the dilution evolutio as part of his normal responsibilities, recognised the need to dilute the RCS l It was amosasary to irjeet appmaimately 30 gallons of primary makeup water (PM l RCS. The FMW iqjection rate was to be about 35 gallons per minute; thersibre, t dihmion evolution was to have lasted less than one mimite. Once this evolution w the ERCO tiled to bliow it to its proper completion in that he responded to an ann (B 9) and subsequently lett the immediate area.

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s. The operstor's integrated performance was not Aastely evaluated by superv i

The BRCO's training and personnel records were reviewed ibr insight into his past l

performanos. The subject received an "Unaa+Way" rating in his May 1995 si l evskistion (control board operations) and was placed on the opemtor norsiuslide i

Ator . dktics and reeW*m the subject received an individual rating of l " Sat / Marginal- Safety SI :"~* " Upon further remediation the subject received l individual rating of "*et M~y" (6/2/95). The BRCO was identi8ed in a Training l department memo (9/s/95) as a Historical Poor Performer due to hiling a st l June 1995 and simulator performance exam in May 1995. In particular, the memo noted 1

that he is "in too much of a hurry, and doesnt communicate well." Other noted observations taken from simulator evaluation summary forms and perfbrmance reviews L

- "need to work ou communications" and "should mark time / level whe i

monitoring containnwns sump" simulator evaluation of 4/2954; i

' - " failed to reshse that pressurizer safhty valve was open" - simulator I svaluados of11/6/95; i

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- "essily diverted and needs to improve in this area" - performance i review 11/10/94, i

This review of training and perfortnance susgests that the qualiscation of the 1

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Ah Raisina 1 j ladividual abould have been more closely scrutintzed by Operations and Training i -

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1 l b. There was no supervisory involvement at the start of the dilution.

l Neither the dilution procedure, OP l 0250020

• Boron Concentradon Control -

i Normal Operation", nor the " Conduct of Operations" procedure require the BRCO to inform the ANPS or other watchstanders of the initiation of any boration or dilution evolutions. Berating or diluting the RCS changes the reactivity of the reactor oore and l ehould be considered a signiScant evolution. Given that there was no procedural i requirements er any type ofnodfication at St. Lucie, the BRCO was not de6cient in this l arse. Had this been a plant policy, the ANPS (or other watchstanders) would have been

! aware of the evolution and may have recognized and corrected the error of the BRCO.

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2) Conduct of 0perations espectations are not ibily understood or consistently applied.

) The BRCO let the RTOB area and went 'over the line" to the hitchen. During this i trendtion, he turned over the RT05 watch to the DRCO who was returning tom the kitchen.

! Appendix D of the " Conduct of 0perations' procedure provides instructions fbr providias

! a turnover ihr 'short term relief" whleh is de6ned as less than two hours. According so the

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procedure, minknuin turnover requirementa conelet of providing: a general watch station status; otr. normal conditions; and testiin progress. Operadons =- ; r^'s enpestation is that short term tumover is applied whenever a watchstaler goes 'over the line" and is out

! ofilne ofsight ofthe board. However, based on interview of seven operstore aAer the event, j this expectation is not clearly understood by operators. A proper turnover may have

prompted the BRCO to recall the dilution and take appropriate action. Misunderstanding of such a ibadarnemal policy indicates a weakness in monitoring of the implementation of poliales and expectations by management Manassinents expectation of' verbatim' compliance to procedure does not ibily recognize the quality of current procedures nor accountability for instances of non cornpliance.

Pmoedure OP.1 0250020 did not contain sufBeient detail to permit " verbatim' compliance, yet none of the operators identl8ed the need fbr a procedure change. In thct most of the, operstorsinterviewed aAer the event felt that this evolution should not require a procedure.

They feltit was "sidil of the creA ' .

3) Raoent plant events involving operator personnel errors have been previously identi5ed and correedve actions have not been completely effbetive.

A WA assessment, Technical Review Report #1TR 95-023, performed at the request of the site Vice President, reviewed sixteen events that occurred sinog August 1995, identi8ed that many of the events' corroetive actions did not go ihr enough to address all potential causal factors. R concluded that many similar events had a medium to high probability fbr recurrence 4

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! 4) '!he plant's Operating Experience Feedback program did not respond to similar reactivity

management events at other nuclear plants.

Because ofa number ofindustry evens involving reactivity management, INPO lesued a sisninoant opwating axpwienee mopen (sona) 94-2, which aleted tim ladustry to the

! Importanos ofrencevity managunent dudng nonnel operadon. This report included a dilution i event very similar to the St. Lucie event which occurred at Ibrkey Point in October 1993.

! In responding to the report, the plant did not identify routine dilutions as an evolution that

! 881ulmd specialattention.

i S) Llosaned Operator sap H8 ~*6 Laining lbouses principally on abnormal or energency j situatican. -

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l Iasson plans and simulator expaience deal almost exclusively with abnormal or emergsasy i altustions As a result, routino evolutions, which are oAen the precursor of abnormal or

{ ensorgeney events, tend to have less signl8canos.

} 6)'Ibe plant's Self Assessment Programs have not been fully edisctive in preventing focurrence ofproblems. -

As discussed earlier, the Quality Assurance organisation has identifled operator

pedhnnance shortcomings where corrective actions have not been Aally eHbetive.

! AM*la==l --na ht&d durine the n= rd= -dM =mt fhnhar !=r!- d=

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1) Plant procedures do not specify the preAured method of making boration or dilution l clumges.

I l Operating Procedure OP 1 0250020 " Boron Concentration Control Normat operation' l allows several flowpaths for diNtion. The procedure does not state which flowpath is

' prethrred fbr making boron concentre!ca changes. A note in section 8.1.7 states that

'Malmuy tom the Beson concentration control system can be directed to either the VCT (br long tenn eEksts, in any mode of operation) or the Charging Pump suction (for short tenn edhuts), in the MANUAL or BORATE modes of operation.' Section 8.5 " Manual Mode of l

, Opension" anows blending directly to the VCT or use of a direct path to the charging pump

! suction. Dilution via the Volume Control Tank provides a slower reactivity response and la j this inadent may have abowed ihr recovery pdor to power escalation. Dilution via the VCT i

also inngthens the duration of the evolution. Operations nest evaluate the various Sowpsth options ihr maldag boron concentration changes, identify the preferred methods and revise procedures accordingly.

I j 2) The prendos fbr operating at the Technical Sp-M~ don limit for T, provided no operating j margin.

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Mueh 6,1996 l Anasimmes Asvineni For PEL Unit 1, the limit for DNB considerations for cold leg temperature is less than or i equalto 549F. The St. Lucie plant practice to operate cold leg temperature at the Todmica!  ;

SpeciSantion limit of 549F did not provide margin for error. Changing RCS boren

canonaration is a normal plant operation, compensating fbr long term rusativity meers, mob

as Rael depletion, xenon buildup and decay, plant startups, shutdowns, or changes in reactor i j power. As the cycle progresses, the RCOs are required to make more toquent reactivity l manipulations, resulting in a higher chance of occurrence of an error due to lessened sense 1 d8WSrWiest ofImportance.

3) Look of anamalation and indication during this event.

i i A control room slarm responding to a dilution evolution in proyees annunciates only when the dilution becomes ancessive. The only alarm to annunciate in the consivt room as a result

! of this over-dilution event was M-16, RCP CONT BLDOFF PRESS HIGH, which was caused by rising Volume Control Tank (VCT) Pressure as reactor coolant inventory j incremend. An alarm for RCS high cold leg temperature is available, but to avoid nuisance

! alarms (operator distraction), the alarm setpont is appseximately 3F greater than the applicable Limiting Condition for Operation of 549F. Similasty, a Delta T Power alann (Point

ID 742) on the plant DDPS computer is no longer maintained in a functional status l 4) The UFSAR has not been maintained current with regard to operating practices.

! F5L 1 UFSAR Section 9.4.2.3 primarily discusses boration and dilution utilizing the j automatic mode of operation. Little discussion is provided regarding the manual mode of operation. No speciSc discussion regarding dilution directly to the charging pump suction j is provided in this section of the UPSAR. St. Lucie operators have historically made

! reactivity changes via the manual mode of operation. Discrepancies between the PSL UFSAR l and existing operating practices are a recognized probiera at St. Lucis. A recent QA audit l Pinding and an NRC deviation have provided examples of this issue. The UFSAR has been

rnalatained current with regard to physical plant changes via the plant chango'rradwadaa (PC/M) process The UFSAR has not always been maintained current with regent to j descriptions ofoperating practices, procedures and administrativo details. The UFSAR has

not been routinely referred to during the periodic review of plant procedures or during the procedure revialon process to ensure continuing agreement with plant operating practices The plant staffs recognition of this event's significance was slow.

4 Raet Csaser The root cause of this probiern is lack of a well defined threshold for recognizing safety

. signi5canos. The operating crew quickly diagnosed the problem, took quick and appropriate l corrective action prior to challen5 ng i any safbty systems and reported the event in that i

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l context. l'- y should have recognized that In House Event Reports and HPES l latervestions identify issues of safisty signlicanoe which should be bliowed up more -

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. l i The Is4ouse Event summary had int =s detail to gain management attendon and l l management did not respond aggressively to an unplanned reactivity changs event, sogenbass '

! of signisanos. spesisonny, the DIE did not contain the information that the BRCO had isA

! a reactivity change =*=d=8. Additionally, based on the observed indications otDighai j Dada Proesseing System (DDPS) digital display provided by the operadag crew and NF8 to i

j the STA, the DIE reported that the peak reactor power as 100.2 percent. '"::;r

detailed analysis revealed that reactor power peaked at 101.13 percent. Subsequent to the

! event, Plant and Operations management did not pursue details surrounding the dilution ia a time earns consistent with the event's signl8cance. l 1

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70545, the Operations Supervisor made his routine phoes eau toen edidte to the controt rooms tr a unit status. The NPS reisted details about the event per this phone

! soswersation. Da discussion included corrective actions, the Technica! Se='laa 140  !

l entered and adted, the RCO Chronolc3 ical log entry, individuals involved, initiation of as 3

IHE and DS 7. (Appendix E of the Conduct of Operations procedure requires the Shift

! Supervision to make prompt verbal notificadon fbt unexplained or unplanned reactivity i changes ) Asins5 meed above, the ANPS was prompt with completion of the DS 7 beibre he t

I went off ablA. Review of the DS 7 revealed that the spealSc detaR related to the BRCO i leaving a reactivity change unattended was not included in the report.

Additlanal m_ i IdastflMed durint the event review which warrant fhrther invda=+1aa I ilM$lEla; .

1) The plant staffs initial investigation of this event was less than adequate.

Thors was several initial investigrdons into this event, all of which were independent of each other to a large degree. Prior to the end of the shiR Monday, several independent event reviews took plane. De Operations crew shiR supervision evaluated the event as warranting documentados to 6e Operations Supervisor via a DS 7. The STA also wrote an DIE to site management tr the event. The HPES coordinator interviewed the personnelinvolved. On Tuesday, Operations supervision conducted a ihet finding masting with the ecsw. On Wednesday, Operations management conducted a review of the event. Nine days aAer the event, a cross Amadonal team was ibrmed to review the event and subsequent plant response.

Conertuting causes to the slow and independent efforts included lack of alte procedures br integrated event response investigation, root cause analysis, and self assessment.

AdditionaDy, the level of detau in existing procedures and fuldelines is inadequate in that:

- DS 7 does not conta!n requirements for a significant level of detall, 7

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- The HPES guideline does not contain reporting time or audience requirements, and, '

- there is no procedural guidance on da==1 Ara'ians of event n.ni and appropriate levels of resources required ibt event investigation.

2) The self assessment by the operating crew was less than adequate, na Operadens crew shift supervisor verbelly counseled the RCO ibr laeving his station wkh a dilution in progress, but did not include this level ofdetail in the DS 7. A thorough self manana ==ar of the event abould have been conducted by the crew prior to their leaving the site on the day ofthe event. Contribudng causes to this cmdhlue were the absenos of a degeldvs site self ========= policy and procedure end no continuing training provided to operations personnel on self assessments and pereommel enor analysis.

3) 'the transer o(lessons learned Born a similar event at Turkey Point to St. Lucie was less than adequate.

As previously discussed, a similar event to this one has previously occurred et hukey Point, with simBar countermeasures applied. .

L ANALYRIE OF PHYSICAL PLANT DW'A50NSE DURING EVENT The key safety parameter associated whh this event is departure kom nucients boiling (DNB). 'Ihere were two plant operadng parameters that were notably aftbetad by this event, remator coolant cold leg temperature (T,) and reactor power. Per Technical Speci8estion 3.2.5, T,is limbed to $ 549F and is normally controlled at about 548.9F. As a result of the ddution, T,lacreased to a peak value of 549.7F (per ERDADS). Graphical data showed T.

e above 5497 for err M=4y 50 minutes. Reactor power is normally maintained et 5100 percent. From a review of ERDADS (Q power) and colorimetric power data, it een be inferred that calorimetric power did not saceed 101.13 percent. Interpolation of the data shows that reactor power was above 101 percent for appravi--ly fbur minutes and above 100 persent ihr spy.-J.T.r.tely 50 minutes.

UFSAR section 15.2.4 provida an analysis of the design basis boron dilution events.

These events assume the h$ection of unborated domineralized water into the RCS at a rate of 132 spot (3 charging pumps x 44 spm/ pump). The analysis notes that boros dilution events ero relatively slow events and that there are numerous indications and alarms eveRable to operators (e.g., boronometer, VCr level, makeup flow, VCT isolation). However, should dilution proceed without operator intervention, the event would be terminated by the TWLP or venable high power trip. DNB rado (DNBR)Ilmhs would not be exceeded in such a case. l The subject dilution occurred at a rate of 38 spen. Thus, the event is clearly esveloped by the existing UFSAR analysis fbr a baron dilution ti power event. Additionally, a core ihm map generated Ace DDPS data polled at 0300 (aRor the event) and compared to the data 6om 0200 (belbre the event) Indicated a normal Bux distribution.

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IA641 Maruk6.199s Amshunnes Revisia1 l

4

h conclusion, the baron dilution event ofJanuary 22,1996 was within the design basis and j analysis ofthe plant and did not present a challenge to plant safbty systems or pose a risk to l the hashh and ashty ofthe public. The event was terminated by operators prior to the onset '

4 of the stanns and automatic protective actions provided ibr such an event. '!he Boones i condition of maalanun steady state thennat power was not violated.

! R CORRECTIVE ACTIONS

! EEBRDDd

! 1. The BRCO was removed from licensed operator duties. Complete i

j - 2. Human Resources and Training are developing an assessment and remediation plan for j possible return of the BRCO to licensed operator duties. Complets

3. Lassons lemmed firom this evers were reinforced via supervisory expostations l

j communiosted to Shift Technical Advisors in the areas of. Sensitivity to plant events, In-

! Houes Event summary accuracy and completends o f supponing data, and 10 CFR 50.59 teviews Complete  !

l i

j 4. The Operations Supervisor has discussed with each NPS the purpose and thresholds of

Appendx E, Conduct of Operations, and the necessary noti 6 cations. Complete i i

i Prensduran/Damunants/ Policies

5. The Conduct of Operations Procedure was revised to include the following:

l - Board walk down is now included as pan of the 'Short Term Turnover" process, i

j - Direct supervision of reactivity changes is required by a Senior Reactor Operator, 4

l - kaactor Control Operator is to remain at the controls during all reactivity changes while in progress, ,

- Reactivity changes shall not be tumed over while in progress.

Complete

6. Operations will revise the " Conduct of Opemtions" to clarify "short term tumover".

Examples of when "short term tumover' is required will be included in the revision. This revision should be commun!cated to Operation's personnel by Night Order and discussed with operating crews Training should reinforce these expectations during training sessions and Management should monitor its effectivenus. Complete 1

9  !

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Ir9641 Maruk 6,1996 j Anashemat Revielen t i

! 7. Engineering has performed a 50.59 evaluation to re8ect Operation's practice ofusing ths l ' manual" mode of dilution and boration. (This 50.9 ud! M laciudad in the next annual

! update to the UFSAR.) Complets i s. n=yni.4 as reconvened h the UFSAR review team to complete the review of the

UF5ARversus plant procedures. Sampling completed 2/29T4 Full scope and schedule j due by 341/96. DanDenver 1 9. Opendons wEl revise the " Conduct of Operations' procedure to require a =Aalame level

! ordstan in DS 7 reports so management will have adequate information for ma======* of l the problem. JefWest-Due 341/96 l 10. System and =, - - Engirmering is developing an Event Response procedure. The i 3

procedure will include or reference: Root Cause Analysis techniques, event severity

? classifications and resources required for analysia. This procedure will also include ,

! expectations fbr the team to include cross Ametional membership from: SCE, Operadons,

! Engineering, Maintenance and QA. Turkey Polat's Evem Response Procedure is under j review fbr incorporetion at St. Lucie. Chuck Wood - Due 3/15/96 i

j 11. The procedure upgrade process wit! Include UFSAR review to identify inconsistendes fbr j oorrection. Complete i

l 12. For the balance of plant procedure not capmrod in the upgrade process, Information Services will ensure that the UFSAR is examined during the three year procedure review l ,

1 process and that inconsistencies are noted and corrected. Jim Holt - Due 3/15/96 1 I

l Equipment Ph l 13. The Plant Oeneral Manager has reemphasized the reduction of nuisance alarms to al line organizations to support the ' blackboard' concept for operations. Complete l

l 14. Engineering is evaluating the current controi rcom annunciation for possible improvements i to help focus awareness of reactivity changes Dan Denver - Due 3/31S6

15. OST will survey the industry on the use of automatic and manual boration and dilution i controls to benchmark St. Lucis and detensine best means of reactivity changes by j obemicalcontrol. Complete Tralnlap & Quality Amarance l,

! 16. AllDS 7s, Operational Events, will be transmitted to the Training Departmord for lessons i learned to be included in the training program. Complete i

j 17. QA should evaluate performing a ' performance baced audit on the adequacy and I

{ 10 i

i

I h

L0661 Mush 6,1996 l

' 'h Raisioni ef8potiveness of the corporate program for transibrring lessons learned between Turkey Point and 8t. Imele for events which occur at the other alte, and fbr events wklah ooour in the industry. Wes Bladow - Due 3/15/96 Supervialan and Management I

18. Operations will review the current watchstanders for Historical Poor Performance, and assess noodibt action. Complets

19. A Training and Performance Review Board will be ktstituted to conduct a consoudsted inview of al perfbrmance indicators idt licensed operations personnel who are identitled as Missorical Poor Portuners. The review will assess the need ibr additional remedial sneesses and/or the removal of the Historical Poor Perfbrmer earn Bosnsed duties.

l

20. Plant management has developed a mechanisen for providing feedback on the

! understanding and '=r'- "Wa of all policies and expectations for all plant l organisations. (Standards Assessment Guldeline by Management) Complete l

i

21. A review was undertaken to evaluate the adequacy of the edsdng policy and guidance involving reactivity control Plant management will now reinforce ==*Was and the importance of reactivity control in a personal letter from the Plant General Manager and Site Vios President to sech RCO and SRO. Complete

22. Operating crew lxidige by Operations Supervision were held discussing the dilution event, Zach Pate's "The Control Room" and managemem's +5+ Mons with respect to conservative plant operation. Operations Supervision also reinforced expectations in

" Conduct of Operations" with respect to notlacation of Operadoes Management, tog keeping, ibous on reactivity changes, and the ahort term tumover process. Complete

23. Operations Management reviewed its expectations for command and control using labrmation obtained from other sites including Turkey Polat. De ireplications of this event will also be reviewed by a team for applicability to other operation's activides both ladde and outside the control room. J. A. West - STAR 960146B & C - SMh dus 3/31/96

24. Nuclear Plant Supervisors have been directed to avview a!! new In-House Events at the 0740 meeting with Plant Management to help prioritize activities. Complete

25. In addition to s@ corrective actions, plant management will seEassess the operation of St. Lucia pant. This self assessment will include, but is not limited, to conduct of Operations, alarm setpoint poucv, opemting =r.'s ibedback. training, procedures, .

corrective actions, and management policies. This review will be pafonned by plant personnel augmented by experienced individuals from off site. Recommended actions will 11

, e - - - -

-e..

Membs,less LWI amisioni

^8hdens .

be reviewed and statused in the momNy indicator book. Independent oversight of this self assessment will be provided via the Company Nuclear Review Board. Jim Searola -

Raport due 7/J1/96 I

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i L-96-61 March 6,1996

- U. S. Nuclear Regulatory Commission i Attn: Document Control Desk l Washington, DC 20555 Re: St. Lucie Units I and 2 ):

Docket Nos. 50-335 and 50-389 Excess Dilution of the Reactor Coo' ant System Due.to Personnel Error .

Nuclear Problem Reoort 96-008. Revision 1 As the result of an event involving the excess dilution of the Reactor Coolant System at St. I l

Lucie Unit 1 on January 22, 1996, Florida Power & Light Company (FPL) initiated a cross-functional investigation to determine root cause and corrective actions. On February 21,1996, an interim Nuclear Problem Report (NP)96-008 was issued discussing preliminary conclusions.

- The purpose of this letter is to forward to the NRC Revision 1 to NP 96-008 which, in addition to presenting the results of the original cross-functional investigation concerning root cause and j corrective actions, includes the event analysis and conclusions of an independent, non-FPL i expert on nuclear plant operations and event analysis. i If you have questions on the attached report, please contact us. l 1

l Very truly yours, W. H Bohlke Vice President St. Lucie Plant Attachment WHB/EJW cc: Stewart D, Ebneter, Regional Administrator, Region 11, USNRC, Atlanta, GA l Senior Resident inspector, USNRC, St. Lucie Plant  !

i l

y_ i 9_a

L-96-61 March i 6, 1996 l Attachment Revision 1  !

ST. LUCIE PLANT NP-700 PROBLEM REPORT 96-008 l

L EVENT TITLE Excess Dilution of the Reactor Coolant System Due to Personnel Error.

St. Lucie Unit i Event Date: 22 January,1996 IL INITIAL PLANT CONDITIONS Unit I was at 100 percent power, steady state operations.

IIL EVENT SEOUENCE At approximately 0220 on January 22,1996 normal reactor fuel depletion resulted in an indicated reactor coolant cold leg temperature (T,) of 548.7F. The Board Reactor Control Operator (BRCO) commenced a dilution to the Reactor Coolant System (RCS) in order to restore T, to a temperature of 548.9F. He began a manual dilution with Primary Makeup Water (PMW) at approximately 38 gpm directed to the suction of the IB Charging Pump at approximately 0225. According to the BRCO, shortly after the dilution was commenced annunciator E-9, " Lube Wate Supply Strainer d/p Hi", was received. The BRCO at the controls left the vicinity of RTGB-105 (this is the location of the controls for the boration and dilution system) to acknowledge this alarm on RTGB 102. After responding to the alarm, the BRCO requested that the Desk RCO (DRCO) relieve him at the controls so he might go to the kitchen. The DRCO moved into the vicinity of RTGB-103. The dilution in progress was not communicated by the BRCO during the short term turnover process. The BRCO then left the "at the controls area" and went to the kitchen to prepare his meal.

Approximately five minutes later, the BRCO returned to the control room and heard the PMW integrator " clicking". The BRCO realized the addition of primary makeup water to the RCS was still in progress and immediately took corrective actions to secure the dilution and commenced borating the RCS. The BRCO commenced boration to the suction of the IB Charging Pump for a total in'itial addition of approximately 26 gallons of boric acid and informed the DRCO and the Nuclear Plant Supervisor (NPS) of his actions. At approximately the same time the BRCO was taking corrective action, annunciator M-16 "RCP CONT BLDOFF PRESS HIGH" alarmed, due to a higher than normal Volume Control Tank (VCT) pressure from the increase in VCT level and Pressurizer level as a result of the expansion of RCS inventory from Tave increasing.

The Assistant Nuclear Plant Supervisor (ANPS) was summoned by the NPS to the control room from the kitchen to assist in actions to return the plant to within normal operating parameters. T, was observed to be greater than 549F.

I

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L-96-61 ' March .  ;

- 6, 19 %

, Attachment Revision 1 l

! With the boration started, the NPS and STA reviewed the Technical Specifications and .  !

entered a two hour action statement to restore RCS T, to less than or equal to 549F in

. accordance with Technical Specification Limiting Condition of Operation (LCO) 3.2.5, DNB Parameters. At 0314, indicated T, was returned to less than 549F, and the LCO Action Statement was exited. All other parameters reached normal levels concurrently.

As was later calculated, and confirmed by recorded plant indications, the highest reactor

] power and RCS cold leg temperature during the event was 101.13 percent and 550.8F ,

(single point maximum).

I Before the crew left the' site that morning, several reviews of the event began. The  !

! crew shift supervision verbally counseled the BRCO for leaving his station while a.  !

dilution was in progress. The ANPS also wrote a notification of the event in the form 4

of Data Sheet (DS) 7 (Operations Department Problem Report, Conduct of Operations 1 procedure) and mailed a paper copy to the Operations Supervisor. The ANPS provided j . a verbal notification of the event to the Operations technical supervisor during his normal J. morning tour of the control rooms. The.STA prepared a draft In House Event (IHE) l summary 96-008 to convey the facts of the event to the site management and to initiate a STAR for root cause. determination. The STA also requested that- the Human >

l Performance Evaluation System (HPES) Coordinator be called 'out to investigate the  !;

event. The HPES Coordinator arrived onsite at 0515, reviewed the draft IHE and-conducted interviews with the personnel involved. At the 0740 morning management

, phone call, the Operations Supervisor and the Plant General Manager were provided with j a copy of the IHE. On that same day, the Operations technical supervisor began an I event review which included discussions with the relief crew, RCO chronological review, i i the DS 7, training and performance appraisals related to the BRCO. At the end of the  ;

i' day, the Operations technical supervisor recommended to the Operations Supervisor that t the BRCO be removed from watch standing duties. He also notified the NRC Resident

of the investigation status. -

l On the following day (January 23), the Operations technical supervisor conducted a p fact finding meeting with the crew and bargaining unit representative. Following that j meeting, the Operations Supervisor concurred in the suspension of the BRCO from watch

, standing duties. The Operations technical s spervisor provided the NRC resident with an i  ;. . update to the event. On January 26, the RIE was updated by the HPES Coordinator to include all of the facts learned about the event during the week. At the direction of the-

. Plant General Manager, on January 31, 1996, a cross functional team was formed to review the event and subsequent plant staff response.

d IV_, ANALYSIS

. The team identified two primary problems for this event. They are discussed in detail below.

4 2

4 L-96-61 March

6. 1996 Attachment Revision 1 PROBLEM 1:

A reactivity evolution was initiated without adequate controls.

Root Cause:

Routine boron dilutions to maintain 100 percent power are not treated with the same importance as oths reactivity management evolutions. This is particularly true toward the end of core life when frequent small additions of primary water are injected in to the RCS to maintain 100 percent power.

fatributine Factors:

1) Cognitive error on the part of the BRCO who initiated the dilution evolution. The BRCO, as part of his normal responsibilities, recognized the need to dilute the RCS and concluded it was necessary to inject approximately 30 gallons'of primary makeup water (PMW) into the RCS. The PMW injection rate was to.be about 38 gallons per minute; therefore, the entire dilution evolution was to have lasted less than one minute. Once this evolution was initiated, the BRCO failed to follow it to its proper completion in that he responded to an annunciator (E-9) and subsequently left the immediate area.

a. The operator's integrated performance was not adequately evaluated by supervision.

The BRCO's training and personnel records were reviewed for insight into his -

past performance. The subject received an " Unsatisfactory" rating in his May 1995 simulator evaluation (control board operations) and was placed on the operator non-qualified list. After remediation and reevaluation, the subject received an individual rating of " Sat / Marginal - Safety Significant." Upon further remediation the subject received an individual rating of " Satisfactory" (6/2/95). The BRCO was identified in a Training department memo (9/8/95) as a Historical Poor Performer due to failing a static exam in June 1995 and simulator performance exam in May 1995.- In particular, the memo noted that he is "in too much of a hurry, and doesn't communicate well." Other noted observations taken from simulator evaluation summary forms and performance reviews:

"need to work on communications" and "should mark time / level when monitoring containment sump" - simulator evaluation of 4/29/94;

" failed to realize that pressurizer safety valve was open" -

simulator evaluation of 11/6/95;

" easily diverted and needs to improve in this area" - performance review 11/10/94.

3

4

.L 96 March 6, 1996

' Attachment Revision I

! This review of training and performance suggests that the qualification of the

individual should have been more closely scrutinized by Operations and Training  !

Management.

h b. There was no supervisory involvement at the start of the dilution.

j- Neither the dilution procedure, OP l-0250020 " Boron Concentration Control -

~

Normal Operation", nor the " Conduct of Operations" procedure require the BRCO to

= inform the ANPS or other watchstanders of the i~nitiation of any boration or dilution evolutions. Borating or diluting the RCS changes the reactivity of the reactor core and should be considered a significant evolution. Given that there was no procedural requirements for any type of notification at St. Lucie, the BRCO was not deficient in this area. Had this been a plant policy, the ANPS (or other watchstanders) would have been aware of the evolution and may have recognized and corrected the error of I the BRCO.

]

2) Conduct of Operations expectations are not fully understood or consistently applied. ,

i The BRCO left the RTGB area and went "over the line" to the kitchen. During this l transition, he turned over the RTGB watch to the DRCO who was returning from the i kitchen. Appendix D of the " Conduct of Operations" procedure provides. instructions for i providing a turnover for "short term relief" which is defined as less than two hours. i According to the procedure, minimum turnover requirements consist of providing: a i general watch station status; off-normal conditions; and tests in progress. Operations management's expectation is that short term turnover is applied whenever a watchstander goes "over the line" and is out of line of sight of the board. However, based on ,

interview of seven operators after the event, this expectation is not clearly understood by operators. A proper turnover may have prompted the BRCO to recall the dilution and take appropriate action. Misunderstanding of such a fundamental policy indicates a weakness in monitoring of the implementation of policies and expectations by management.

Management's expectation of " verbatim" compliance to procedure does not fully recognize the quality of current procedures nor accountability for instances of non compliance. Procedure OP-1-0250020 did not contain sufficient detail to permit

" verbatim" compliance, yet none of the operators identified the need for a procedure change, in fact most of the operators interviewed after the event felt that this evolution j should'not require a procedure. They felt it was " skill of the craft."

3) Recent plant events involving operator personnel errors have been previously identified and corrective actions have not been completely effective.

A Q/A assessment, Technical Review Report #1TR 95-023, performed at the request of the site Vice President, reviewed sixteen events that occurred since August 1995, 4

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l L-%-61 March

.6,1996 f Attachment Revision 1

. identified that many of the events' corrective actions did not go far enough to address all potential causal factors. It concluded that many similar events had a medium to high probability for fecurrence.

4) The plant's Operating Experience Feedback program did not respond to similar reactivity management events at other nuclear plants.

l Because of a number ofindustry events involving reactivity management, INPO issued ,

a Significant Operating Experience Report (SOER) 94-2, which alerted the industry to l the importance of reactivity management during normal operation. This report included a dilution event very similar to the St. Lucie event which occurred at Turkey Point in October 1993. In responding to the report, the plant did not identify routine dilutions j

as an evolution that required special attention. ,

i I l 5) Licensed Operator Requalification Training focuses principally on abnormal or

emergency situations.

l Lesson plans and simulator experience deal almost exclusively with abnormal or i emergency situations. As a result, routine evolutions, which are often the precursor of e

abnormal or emergency events, tend to have less significance.

6) The plant's Self Assessment Programs have not been fully effective in preventing .

recurrence of problems.

L l As discussed earlier, the Quality Assurance organization has identified operator i performance shortcomings where corrective actions have not been fully effective. ]

! Additional concerns identified durine the event review which warrant further I investination include:

i i 1) Plant procedures do not specify the preferred method of making boration or dilution

changes.

Operating Procedure OP l-0250020 " Boron Concentration Control-Normal Operation" l allows several flowpaths for dilution. The procedure does not state which flowpath is  ;

preferred for making boron concentration changes. A note in section 8.1.7 states that

~

" Makeup from the Boron concentration control system can be directed to either the VCT (for long term effects, in any mode of operation) or the Charging Pump suction (for short.

j term effects), in the MANUAL or BORATE modes of operation." Section 8.5 " Manual Mode of Operation" allows blending directly to the VCT or use of a direct path to the

_ charging pump suction. Dilution via the Volume Control Tank provides a slower j reactivity response and in this incident may have allowed for recovery prior to power escalation. Dilution via the VCT also lengthens the duration of the evolution.

1 - Operations must evaluate the various flowpath options for making boron concentration 5

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4

~L-96-61 March

6, 1996 Attachment

• Revision 1 I changes,' identify the preferred methods and revise procedures accordingly.

I 2) The practice for operating at the Technical Specification limit for T, provided no operating margin. )

• 1 1

For PSL Unit 1, the limit for DNB considerations for cold leg temperature is less than )

1 or equal to 549F. The St. Lucie plant practice to operate cold leg temperature at the j

. Technical Specification limit of 549F did not provide margin for error. Changing RCS l boron concentration is a normal plant operation, compensating for long term reactivity

~

I

. effects, such as fuel depletion, xenon buildup and decay, plant startups, shutdowns, or  !

l changes in reactor power. As the cycle progresses, the RCOs are recluired to make more  ;

i- frequent reactivity manipulations, resulting in a higher chance of oci urrence of an error l due to lessened sense of awareness or importance.

3) Lack of annunciation and indication during this event.

A control room alarm responding to a dilution evolution ir. progress annunciates only  ;

when the dilution becomes excessive. The only alarm to armunciate in the control room ,

! as a result of this over-dilution event was M-16, RCP CONT BLDOFF PRESS HIGH, j

, which was caused by rising Volume Control Tank (VCT) Pressure as reactor coolant _j

inventory increased. An alarm for RCS high cold leg temperature is available, but to  !

avoid. nuisance alarms (operator distraction), the alarm setpoint is approximately 3F i

! greater than the applicable Limiting Condition for Operation of 549F. Similarly, a Delta-  ;

T Power alarm (Point ID-742) on the plant DDPS computer is no longer maintained in a functional status.

'I l 4) The UFSAR has not been maintained current with regard to operating practices. l 1

?

l PSL-1.UFSAR Section 9.4.2.3 primarily discusses boration and dilution utilizing the >

automatic mode of operation. Little discussion is provided regarding the manual mode  ;

6 of operation. No specific discussion regarding dilution directly to the charging pump i suction is provided in this section of the UFSAR. St. Lucie operators have historically j made reactivity changes via the manual mode of operation. Discrepancies between the l ' PSL UFSAR and existing operating practices are a recognized problem at St. Lucie. A recent QA audit Finding and an NRC de'viation have provided examples of this issue.

The UFSAR has been maintained current with regard to physical plant changes via the

. plant change / modification (PC/M) process. The UFSAR has not always been maintained '

current with regard to descriptions of operating practices, procedures and administrative ,

details. The UFSAR has not been routinely referred to during the periodic review of

^

plant procedures or during the procedure revision process to ensure continuing agreement with plant operating practices.

- l PROBLEM 2:

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Attachment Revision I d r The plant staff's recognition of this event's significance was slow.

~

. Root Cause:

The root cause of this problem is lack of a well defined threshold for recognizing safety significance. The operating crew quickly diagnosed the problem, took quick and appropriate corrective action prior to challenging any. safety systems and reported the ,

event in that context. Management should have recognized that In House Event Reports and HPES interventions identify issues of safety significance which should be followed

, up more aggressively.

! Contributine Factors:

The In-house Event summary had insufficient detail to gain management attention and management did not respond aggressively to an unplanned reactivity change event, regardless of significance. Specifically, the IHE did not contain the information that the j BRCO had left a reactivity change unattended. Additionally, based on the observed indications of Digital Data Processing System (DDPS) digital display provided by the

- operating crew and NPS to the STA, the IHE reported that the peak reactor power as 100.2 percent. Subsequent detailed analysis revealed that reactor power peaked at 101.13 percent. Subsequent to the event, Plant and Operations management did not pursue details surrounding the dilution in a time frame consistent with the event's significance.

j- At approximately 0545, the Operations Supervisor made his routine phone call from offsite to the control rooms for a unit status. The NPS related details about the event per

this phone conversation. The discussion included corrective actions, the Technical Specification LCO entered and exited, the RCO Chronological log entry, individuals i involved, initiation of an IHE and DS 7. (Appendix E of the Conduct of Operations i procedure requires the Shift Supervision to make prompt verbal notification for ,

. unexplained or unplanned reactivity changes.) As indicated above, the ANPS was I 2

prompt with completion of the DS 7 before he went off shift. Review of the DS 7 l revealed that the specific detail related to the BRCO leaving a reactivity change  ;

unattended was not included in the report.

Additional concerns identified during the event review which warrant further

investigation include

1) The plant staff's initial investigation of this event was less than adequate.

There were several initial investigations into this event, all of which were independent of each other to a large degree. Prioi to the end of the shift Monday, several independent event reviews took place. The Operations crew shift supervision evaluated the event as warranting documentation to the Operations Supervisor via a DS 7. The STA also wrote an IHE to site management for the event. The HPES coordinator 7

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L-%-61 March

6. 1996 j

' Attachment - Revision 1

)

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interviewed the personnel involved. On Tuesday, Operations supervision conducted a  ;

. fact finding meeting with the crew. On Wednesday, Operations management conducted  !

a review of the event. Nine days after the event, a cross functional team was formed to i review the event and subsequent plant' response. Contributing causes to the slow and  ;

independent efforts included lack of site ' procedures for integrated event response j investigation, root cause analysis, and self assessment. Additionally, the level of detail 1 in existing procedures and guidelmes is madequate in that

)

, i

- DS 7.does not contain requirements for a~significant level of detail, i .

The HPES guideline does not contain reporting time or audience requirements, and, there is no procedural guidance on classifications of event severity and appropriate levels of resources required for event investigation.

i

2) The self assessment by the operating crew was less than adequate. l 4

The Operations crew shift supervisor verbally counseled the RCO for leaving his j

- station with a dilution in progress, but did not include this level of detail in the DS 7.-

j A thorough self assessment of the event should have been conducted by the crew prior  ;

to their leaving the site on the day of the event. Contributing causes to this condition

were the absence of a definitive site self assessment policy and procedure and no continuing training provided to operations personnel on self assessments and personnel error analysis.

]

3) The transfer of lessons learned from a similar event at Turkey Point to St. Lucie was less than adequate. ,

i As previously discussed, a similar event to this one has previously occurred at Turkey I Point, with similar countermeasures applied.

.V a ANALYSIS OF PHYSICAL PLANT RESPONSE DURING EVENT The key safety parameter associated with this event is departure from nucleate boiling (DNB). There were two plant operating parameters that were notably affected by this event, reactor coolant cold leg temperature (T,) and reactor power. Per Technical Specification 3.2.5, T, is limited to A 549F and is normally controlled at about 548.9F. l As a result of the dilution, T, increased to a peak value of 549.7F (per ERDADS). I Graphical data showed T, above 549F for approximately 50 minutes. Reactor power is normally maintained at i 100 percent. From a review of ERDADS (Q power) and calorimetric power data, it can be inferred that calorimetric power did not exceed 101.13 percent. Interpolation of the data shows that reactor power was above 101 percent for approximately four minutes and above 100 percent for approximately 50 minutes.

I 8

t L-9641 March 6, 1996 Attachment Revision 1 UFSAR section 15.2.4 provides an analysis of the design basis boron dilution events, j- These events assume the injection of unborated demineralized water imo the RCS at a rate of 132 gpm (3 charging pumps x 44 gpm/ pump). The analysis notes that boron i

. dilution events are relatively slow events and that there are numerous indications and a alarms available to operators (e.g., boronometer, VCT level, makeup flow, VCT l isolation). However, should dilution proceed without operator intervention, the event ,

would be terminated by the TM/LP or variable high power trip. DNB ratio (DNBR) l l limits would not be exceeded in such a case. The subject dilution occurred at a rate of 38 gpm. Thus, the event is clearly enveloped by the existing UFSAR analysis for a L boron dilution at power event. Additionally, a core flux map generated from DDPS data

polled at 0300 (after the event) and compared to the data from 0200 (before the event) j indicated a normal flux distribution. ,

1 4' In conclusion, the boron dilution event of January 22,1996.was within the design

, basis and analysis of the plant and did not present a challenge to plant safety systems or g pose a risk to the health and safety of the public. The event was terminated by operators i

prior to the onset of the alarms and automatic protective actions provided for such an ,

event. The license condition of maximum steady-state thermal power was not violated, j i

i _VL CORRECTIVE ACTIONS

$ Persont.el I

l

l. 1. The BRCO was removed from licensed operator duties. Complete 4 '2. Human Resources and Training are developing an assessment and remediation plan for possible return of the BRCO to licensed operator duties. Complete

3. Lessons learned from this event were reinforced via supervisory expectations 3 communicated to Shift Technical Advisors in the areas of

Sensitivity to plant events,  !

In-House Event summary accuracy and completeness of supporting data, and 10 CFR 50.59 reviews. Complete

4. The Operations Supervisor has discussed with each NPS the purpose and thresholds of Appendix E, Conduct of Operations, and the necessary notifications. Complete Procedures / Documents / Policies

[ 5. The Conduct of Operations Procedure was revised to include the following:

i-Board walk down is now included as part of the "Short Term Turnover" process, Direct supervision of reactivity changes is required by a Senior Reactor Operator, i

e f 9 I' . _ _ __

- . - . -. - . . - . . = . . _ - - . _ . - - . . . -. .-. . - = . .-- .

1 l

i-L-96-61i March .

6, 1996 l Attachment Revision 1

]

Reactor Control Operator is to remain at the controls during all reactivity changes  !

while in progress, )

Reactivity changes shall not be turned over while in progress.

L Complete

6. Operations will revise the " Conduct of Operations" to clarify "short term turnover".

Examples of when "short term turnover" is required will be included in the revision.

This revision should be communicated to Operation's personnel by Night Order and discussed with operating crews; Training should reinforce these expectations during -

training sessions and Management should monitor its effectiveness. Complete

7. Engineering has performed a 50.59 evaluation to reflect Operation's practice of using '

the " manual" mode of dilution and boration. (This 50.59 will be included in the next annual update to the UFSAR.) Complete

8. Engineering has reconvened the UFSAR review team to complete the review of the UFSAR versus plant procedures. Sampling completed 2/29/96. Full scope and

. schedule due by 3/31/96. Dan Denver L9. Operations will revise the " Conduct of Operations" procedure to require a sufficient level of detail in DS 7 reports so management will have adequate information for assessment of the problem. Jeff West - Due 3/31/96 10.- System and Component Engineering is developing an Event Response procedure. The

~

- procedure will include or reference: Root Cause Analysis techniques, event severity classifications and resources required for analysis. This procedure will also include expectations -for the team to include cross functional membership from: SCE, Operations, Engineering, Maintenance and'QA. Turkey Point's Event Response .

Procedure is under review for incorporation at St. Lucie. Chuck Wood - Due 3/15/96

11. The procedure upgrade process will include UFSAR review to identify inconsistencies for correction. Complete-

12. For the balance of plant procedure not captured in the upgrade process, Information Services will ensure that the UFSAR is examined during the three year procedure review process and that inconsistencies are noted and corrected. Jim Holt - Due 3/15/96 Eauioment Performance

13. The Plant General Manager has reemphasized the reduction of nuisance alarms to all line organizations to support the " blackboard" concept for operations. Complete 10

. . -. ~ = . - .- .. . _ . . . - - - _ _ . . - - . - . - _

~ ~ ~ - . - - - -

4 4

L-96-61 March

. 6, 1996 I

Attachment Revision 1 j 14. Engineering is evaluating the current control room annunciation for_ possible improvements to' help focus awareness of reactivity changes. Dan Denver - Due 3/31/96 1- 15. OST will survey the industry on the use of automatic and manual boration and dilution controls to benchmark St. Lucie and determine best means of reactivity changes by chemical control. Complete Training & Ouality Assurance

. 16. All DS 7s, Operational Events, will be transmitted to the Training Department for j- lessons leamed to be included in the training program. Complete

17. QA should evaluate performing a performance based audit on the adequacy and

~

effectiveness of the corporate program for transferring lessons learned between Turkey i Point and St. Lucie for events which occur at the other site, and for events which occur in the industry. Wes Bladow - Due 3/15/96 Suoervision and Management 2

l 18. Operations will review the current watchstanders for Historical Poor Performance, and

{ assess need for action. Complete 4

i 19. A Training and Performance Review Board will be instituted to conduct a consolidated review of all performance indicators for licensed operations personnel who are identified as Historical Poor Performers. The review will assess the need for  :

additional remedial measures and/or the removal of the Historical Poor Performer l from licensed duties. Complete

, 20. Plant management has developed a mechanism for providing feedback on the understanding and implementation of all policies and expectations for all plant

! organizations. (Standards Assessment Guideline by Management) Complete

21. A review was undertaken to evaluate the adequacy of the existing policy and guidance involving reactivity control. Plant management will now reinforce expectations and the importance of reactivity control in a personal letter from the Plant General Manager and Site Vice President to each RCO and SRO. Complete ,

i l

22. Operating crew briefings by Operations Supervision were held discussing the dilution 4 event, Zach Pate's "The Control Room" and management's expectations with respect to conservative plant operation. Operations Supervision also reinforced expectations

in " Conduct of Operations" with respect to notification of Operations Management, log keeping, focus on reactivity changes, and the short term turnover process.

Complete 11 i,

..m_. _. ._.._m.__, _ . , ._ .. _ _ _ _ -

i -)

i- -

1A6-61 March i 6.1996 4

Attachment Revision 1 l t -l

23. Operations Management reviewed its expectations for command and control using j

information obtained from other sites including Turkey Point. The implications of this j i event will also be reviewed by a team for applicability to other operation's activities .!

both inside and outside the control room. J. A. West - STAR 960146B l

& C - Schedules due 3/31/96 1 4 l

24. Nuclear Plant Supervisors have been directed to review all new In-House Events'at  ;

l i the 0740 meeting with Plant Management to help prioritize activities. Complete l

! I j  : 25. In addition to specific corrective actions, plant management will self-assess the l

[ operation of St. Lucie plant. This self-assessment will include, but is not limited, to.

Conduct of Operations, alarm setpoint policy, operating experience feedback, training, j

procedures, corrective actions, and management policies. This review will be performed by plant personnel augmented by experienced individuals from off-site, i Recommended actions will be reviewed and statused in the monthly indicator book, i- Independent oversight'of this self-assessment will be provided via the Company.

l. Nuclear Review Board. Jim Scarola - Report due 7/31/96 i

I i

,t -

l l

12 i

1 l

l PREDECISIONAL ENFORCEMENT CONFERENCE AGENDA l I

l

ST LUCIE MARCH 8,1996, AT 10

30 A.M.

NRC REGION 11 OFFICE, ATLANTA, GEORGIA l

l '

l l 1. OPENING REMARKS AND INTRODUCTIONS i S. Ebneter, Regional Administrator i  !

11. NRC ENFORCEMENT POLICY l l B. Uryc, Director Enforcement and Investigation Coordination Staff 111.

SUMMARY

OF THE ISSUES S. Ebneter, Regional Administrator l IV. STATEMENT OF CONCERNS / APPARENT VIOLATIONS l A. Gibson, Director l Division of Reactor Safety '

V. LICENSEE PRESENTATION T. Plunkett, President - Nuclear Division Florida Power & Light Company ,

VI. BREAK / NRC CAUCUS Vll. NRC FOLLOWUP QUESTIONS Vill. CLOSING REMARKS S. Ebneter, Regional Administrator I

-w. -

i i

EXPECTED ATTENDEES i

Licensee I -

l Tom Plunkett, President - Nuclear Division, FPL j Bill Bohlke, Vice President, St. Lucie Nuclear Plant i Jim Scarola, Plant General Manager, St. Lucie ,

j Dan Denver, Engineering Manager, St. Lucie

} Ed Weinkam, Licensing Manager, St. Lucie

! Peter Honeysett, Nuclear Plant Supervisor, St. Lucie

Frank Cone, Reactor Controls Operator, St. Lucie 1

Hank Holzmacher, Reactor Controls Operator, St. Lucie MEC Stew Ebneter, Regional Administrator, Region ll (Rll)

Luis Reyes, Deputy Regional Administrator, Ril Al Gibson, Director, Division of Reactor Safety (DRS), Ril Ellis Merschoff, Director, Division of Reactor Projects (DRP), Ril  !

Gene Imbro, Director, Project Directorate ll-2, NRR James Beall, Enforcement Coordinator, Office of Enforcement (OE)  !

Johns Jaudon, Deputy Director, DRS, Ril Jon Johnson, Deputy Director, DRP, Rll Bruno Uryc, Director, Enforcement and Investigation Coordination Staff (EICS), Ril '

Charles Casto, Chief, Engineering Branch, DRS, Ril Tom Peebles, Chief, Operations Branch, DRS, Ril Kerry Landis, Reactor Projects Branch 3, DRP, Ril Jan Norris, Project Manager, NRR Linda Watson, Senior Enforcement Specialist, EICS, Rll Carolyn Evans, Regional Counsel, Ril Mark Miller, Senior Resident inspector, St. Lucie, DRP, Ril Robert Schin, Reactor inspector, Engineering Branch, DRS, Ril Edwin Lea, Project Engineer, Reactor Projects Branch 3, DRP, Ril

-_ _ _ . _ _ _ . . _ _ _ _ _ _ _ _ _ _ _ . _ . . _ _ . _ _ . . . . . _ _ . _ . = _ _ .

i' l-February 26, 1996 .;

EA 96-40 Florida Power and Light Company ATTN: Mr. J. H. Goldberg President - Nuclear Division P. O. Box 14000 Juno Beach, FL 33408-0420

SUBJECT:

CLOSED MEETING ANNOUNCEMENT - PREDECISIONAL ENFORCEMENT CONFERENCE ST. LUCIE - DOCKET N05. 50-335, 389 .

Gentlemen:

This letter confirms the conversation between Mr. E. Benken of your staff and ,

Mr. M. Miller, of the NRC on February 23, 1996, concerning a predecisional i enforcement conference requested by us which has been scheduled for. March 8, 1996, at 10:30 a.m. The purpose of this conference is to discuss apparent violations regarding a January 22, 1996, event involving excessive boron l dilution on Unit 1. The location of the conference will be at the NRC i Region II office, 101 Marietta Street, N.W., Suite 2900, Atlanta, Georgie.

This meeting is a closed meeting as per " Staff Meetings Open to the Public; Final Policy Statement" (September 20, 1994; 59 FR 48340).

Should you have any questions concerning this meeting, please contact Edwin Lea at 404/331-3641.

Sincerely, Orig signed by Kerry D. Landis Kerry D. Landis Reactor Projects Branch 3 Division of Reactor Projects  :

Dncket Nos. 50-335, 389 License Nos. DPR-67, NPF-16 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 3340S-0420 cc cont'd: (See page 2) ,

OFFICIAL COPY >

Mu )Ob v7_h

• 4 i

a l FPC 2 4

cc cont'd:

J. Scarola Thomas R. L. Kindred Plant General Manager County Administrator St. Lucie Nuclear Plant St. Lucie County P. O. Box 128 2300 Virginia Avenue j Ft. Pierce, FL 34954-0128 Ft. Pierce, FL 34982 1

Robert E. Dawson Charles B. Brinkman

. Plant Licensing Manager Washington Nuclear Operations

St. Lucie Nuclear Plant ABB Combustion Engineering, Inc.

< P. O. Box 128 12300 Twinbrook Parkway, Suite 3300 i- Ft. Pierce, FL 34954-0218 Rockville, MD 20852 1

J. R. Newman, Esq. Distribution:

l Morgan, Lewis & Bockius K. Landis, RII i 1800 M Street, NW J. Norris, NRR i Washington, D. C. 20036 G. Hallstrom, RII 4

E. Merschoff, RII

! John T. Butler, Esq. J. Johnson, RII l Steel, Hector and Davis , A. Gibson, RII 3 4000 Southeast Financial Center B. Mallett, RII Miami, FL 33131-2398 B. Uryc, RII 4

A. Gody, DISP /PIPB i Bill Passetti W. Burton, OEDO (017 G21) .

j Office of Radiation Cor. trol R. Martin,-NRR

, Department of Health and J. Lieberman, OE i Rehabilitative Services H. Berkow, NRR

{ 1317 Winewood Boulevard Docket File Tallahassee, FL 32399-0700 PUBLIC

] ,

j Jack Shreve e f-FA <

! Public Courisel Meeting Announcement Coordinator, Office of the Public Counsel OADM/DFIPS (PMNS) i c/o The Florida Legislature RII Administrator's Secretary i 111 West Madison Avenue, Room 812 RII Division Directors and Deputies j Tallahassee, FL 32399-1400 RII Public Affairs Officer 4

{ Joe Myers, Director

' Division of Emergency Preparedness

Department of Community Affairs

, 2740 Centerview Drive i Tallahassee, FL 32399-2100 asuri TO puntic EOCUMENT MOOM7 dR/ NO OFFICE Rll:DRP Rll:DRG Ril:EICS ,

{

SIGNATURE (v h NAME Eles

sam CCasto SWryD -"* '

DATE 02/hl98 02fN 190 02 ll.b S8 e't / 198 02/ /90 02/ /98

! COPY? YES NO YES A'40 iVES . NO YES NO YES NO YES NO j OfflCIAL RECORD COPY DOC *Lnr *.ME: \Jur\STLmtg. lea J

i 0

4 OPENING REMARKS AND INTRODUCTIONS l (S. Ebneter) l i . l

! Good morning. I am Stew Ebneter, Regional Administrator for the '

l Nuclear Regulatory Commission's Region ll Office. This morning we L will conduct a predecisional enforcement conference between the NRC i and St. Lucie which is CLOSED to public observation.  !

1 l

The agenda for the conference is shown in the viewgraph. Following

my brief opening remarks, Mr. Bruno Uryc, the Director of the Region 11 4

Enforcement Staff, will discuss the Agency's Enforcement Policy. I

- will then provide introductory remarks concerning my perspective on

the events to be addressed today. Mr. Albert Gibson, Director of the

(

l Division of Reactor Safety, will then discuss the apparent violations.

You will then be given an opportunity to respond to the apparent 1

violations. In this regard, I wish to reiterate to you that the decision to i

hold this conference does not mean that the NRC w > determined that violations have occurred or that enforcement action will be taken. This conference is an important step in arriving at that decision.

4 1

k

i 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 '

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.

[lNTRODUCTIONS]

Thank you.

Mr. Uryc will now discuss the Agency's Enforcement Policy.

1

+

I 1

NRC ENFORCEMENT POLICY AND PROCEDURE j (B. Uryc)

After an apparent violation is identified, it is assessed in accordance with the Commission's Enforcement Policy, which was recentiy revised and became effective on June 30,1995. The Enforcement Policy has been published as NUREG-1600.

The assessment of an apparent violation involves 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 Level I,-11, or lil, a predacisional 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. 1 Orders may be issued for violations, or, in the absence of a violation, because of a significant public health or safety issue.

1

l This predecisional enforcement conference is essentially the last step of the inspection or investigation process before the staff makes its

i final enforcement decision. l 3

l The purpose of this conference is not to negotiate a sanction. Our i

i purpose here today is to obtain information that will assist us in i

determining the appropriate enforcement action, such as

(1) a

common understanding of the facts, root causes and missed i

opportunities associated with the violations, (2) a common  ;

1 l understanding of corrective action taken or planned, and (3) a common l understanding of the significance of issues and the need for lasting 4

1 i comprehensive action.

The apparent violations discussed at this conference are subject to i further. review and they may be subject to change prior to any resulting 4

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.

4 I should also note at this time that statement of views or the

i i l l

expression of opinion made by the NRC staff at this conference,'or the  !

\

. /ack thereof, are not intended to represent final determinations or. l l .

beliefs.

i i i I I

i 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 4

i about four weeks to accomplish.

i l

Predecisional enforcement conferences are normally closed to the public is is this conference. However, the Commission implemented a trial program in July 1992 to allow certain enforcement conferences to be open for public observation. [ July 10,1992 - Federal Reg / ster]

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 will issue a press release 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the enforcement action is issued.

. 1

SUMMARY

OF THE ISSUES (S. Ebneter) i t

issues

1) Apparent Violations of St. Lucie Operating Procedures for Reactor Coolant System Boron Dilution, Watch Turnover, Adherence to Procedures, and Prompt Reporting of Events l

2) Apparent Violation of 10 CFR 50, Appendix B, Design Control, Requirements in that a Procedure for Adding a Mixture of Demineralized Water and Boric Acid to the Reactor Coolant System did not Implement the Method Stated in the FSAR

3) A'pparent Violation of 10 CFR 50.59 in that a Change was Made to the Unit 1 Procedure for Reactor Coolant System Boron Dilution on January 23,1996, that Differed from the Method Stated in the FSAR, Without Performing a Safety Evalur; tion

1 1

l Consequences:

a i 4 4  !

4 i

Operators allowed an unmonitored reactivity addition, which caused I

! the Unit 1 nuclear reactor to exceed 100% power, and then did not l

l promptly report the event to licensee management. Also, during this event, reactivity was added to the Unit 1 reactor in a method that was 1

different from that described in the FSAR.

l i

i 4

M i

i i

STATEMENT OF CONCERNS / APPARENT VIOLATIONS l (A. Gibson) i .

f This is a Predecisional Enforcement Conference to discuss three i

lr apparent violations. The first one is associated with the apparent i

! violations of operating procedures by licensed operators. These involve i

operators failing to follow procedures for reactor coolant system boron i dilution, watch turnover, adherence to procedures, and prompt

[

i reporting of events. These apparent violations were identified by the

! licensee.

i i

l The second and third apparent violations involve the failure to j implement operating methods described in the FSAR into an operating l

procedure and then changing that procedure to further deviate from .

[ operating methods described in the FSAR, without performing a required safety evaluation. These apparent violations were identified by the NRC.

In view of these apparent violations, we are concerned with licensee control of licensed activities.

Our findings are documented in NRC inspection Report 50-335,38,9/96-03, which was transmitted to you on February 22,1996.

At this conference, we are affording you the opportunity to provide information relative to:

--- Any errors in the inspection report

--- The severity of the violations

--- Any escalation or mitigation considerations Any other application of the Enforcement Policy relevant to this issue.

d ISSUES TO BE DISCUSSED i

i l 1. 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, j 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.

! O'perating Procedure No. 1-0250020, Boron Concentration Control -

. Normal Control, Rev. 35, step 8.5.14 required that, when adding a l blend of primary makeup water and boric acid to the reactor coolant system by using the manual mode of operation and a flow path directly j to the charging pump suction, operators monitor the water flow i

totalizer and close valve V2525 after the desired volume was added.

1

Administrative Procedure No. 0010120, Conduct of Operations, Rev l 79, Appendix D, Crew Relief / Shift Turnover, required that, for short term watchstander relief, a turnover be conducted including

general l 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 Q15-PR/PSL-1. Procedure QI 5-PR/PSL-1, Preparation, Rpvision, Review / Approval of Procedures, Rev 67, Section 5.13.2, stated that all procedures shall be strictly adhered to and 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.

Administrative Procedure No. 0010120, Appendix E, Notification of Operations Supervisor /FPL Management, required prompt verbal notification of the Operations Supervisor for unplanned reactivity i changes.  !

i i

i i l i  !

l a. On January 22,1996, at approximately 9.:30 a.m., Unit 1 l

! operators failed to monitor the water fl ' totalizer and failed to  !

j -

close valve V2525 after the desired volume of primary makeup

water was added to the reactor coolant system when using the e . manual mode of operation and a flow path directly to the

charging pump suction. Operators had desired to add.between

25 and 40 gallons of primary makeup water, but failed to stop j the dilution until approximately 400 gallons were added During 4

this time, the temporary relief operator at the controls was y unaware that a boron concentration dilution was in progress, l which resulted in an unmonitored reactivity addition. The senior

, reactor operator and other operators in the control room were also unaware that a reactivity addition was in progress.

i l b. On January 22,1996, at approximately 2:30 a.m., the Unit 1 j operator at the controls conducted a short term watchstander i relief with an inadequate turnover in that it failed to include general watchstation status and conditions including that a boron concentration dilution was in progress. As a result, the relief i operator at the controls was unaware that a boron concentration j dilution was in progress and failed to adequately monitor and

!- contr01 the dilution.

j' c. 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 j that the' boron concentration dilution that was performed could

not have been performed by strictly adhering to the procedure. l l

! d. On January 22,1996, between 2:30 a.m. and 5:45 a.m.,

i operators failed to give prompt verbal notification to the '

i . Operations Supervisor for unplanned reactivity changes that had

! occurred.

~

)

j NOTE: The apparent violations discussed in this predecisional j enforcement conference are subject to further review and are i subject to change prior to any resulting enforcement decision.

l

l l

lSSUES TO BE DISCUSSED l

2. 10 CFR 50, Appendix B, Criterion Ill, Design Control, requires that  !

measures be established to assure that applicable regulatory requirements and the design basis, as specified in the license application, are correctly translated into procedures. {

Contrary to the above, the design basis, as specified in the license application, was not correctly translated into procedures in that, from approximately January 24,1976 (before the Unit 1 operating license 1 was issued), through January 23,1996, the Safety Analysis Report  ;

description of the method for adding a mixture of boric acid and l primary water to the reactor coolant system had not been correctly )

translated into procedures. The Unit 1 procedure for adding a mixture l of boric acid and demineralized water to the reactor coolant system (in manual and directly to the suction of the charging pumps) was i different from the method stated in the SAR (in automatic and to the.

volume control tank). The method used in the Unit 1 procedure >

allowed adding reactivity faster and without an automatic shutoff.

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.

1 i

! ISSUES TO BE DISCUSSED

[ .

i' .

3. 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 the change involves, in part, an j

unreviewed safety question. A proposed change shall be deemed to '

l involve'an unreviewed safety question if, in part, the probability of l occurrence of an accident important to safety previously evaluated in i the SAR may be increased. The licensee shall maintain records of j changes in procedures made pursuant to this section, to the extent

- that they constitute changes in procedures as described in the SAR.

l These records must include a written safety evaluation which provides

! a basis for the determination that the change does not involve an l unreviewed safety question.

l l Contrary to the above, on January 23,1996, the licensee made a j 4

change to Unit 1 procedures as described in the SAR and the records i l for that change dld not include a written safety evaluation. The SAR, i

paragraph 15.2.4.1, states that beron dilution must be conducted in automatic (such that when the specific amount has been injected, the domineralized water control valve is shut automatically) and describes a flow path into the volume control tank. The SAR states that, in part, ,

! because of the procedures involved, the probability of a sustained or  !

j- erroneous dilution is very low. However, Temporary Change 1-96-017 l to procedure 1-0250020, Boron Concentration Control - Normal l Operation, Rev. 35, added instructions for dilution in manual and

directly to the suction of the charging pumps. The TC allowed adding l reactivity faster than the SAR method and without an automatic l shutoff. The licensee implemented the TC on January 23,1996, l without a written safety evaluation.

I l

I l

i NOTE: The apparent violations discussed in this predecisional i enforcement conference are subject to further review and are i subject to change prior to any resulting enforcement decision.

i

~ - - - - . _ ~ - . . - - - . - - - - -

asee UNITED STATE 8

NUCLEAR REGULATORY COMMISSION y Re010N 11 1 101 MARieTTA STReef. N.W. SUITE 2I00  !

ATLANTA, GEORGIA 3M5415  ?

k, *

• e February 22, 1996 i EA 96-04'O l

Florida Power & Light Company '

ATTN:.-J.'Goldberg .

President - Nuclear Division l P. O. Box 14000 t Juno Beach, Florida 33408-0420 i

SUBJECT:

NRC INSPECTION REPORT NOS. 50-335/96-03 AND 50-389/96-03  !

Dear Mr. Goldberg:

This refers' to the special followup inspection of the January 22, 1996, Unit 1 l overdilution event. The inspection was conducted on January 26-30, 1996, at '

.the St. Lucie facility. This matter was again discussed on February 8, 1996, '

in a meeting'in Atlanta. The purpose of the inspection was to determine  :

whether activities authorized by the license were conducted safely and in  !

accordance with'NRC requirements. At the conclusion of the inspection, the findings were discussed with you and 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. . l Based on the results of this inspection, three apparent violations were identified and are being considered for escalated enforcement action in accordance with the " General Statement of Policy and Procedure for NRC f Enforcement Actions" (Enforcement Policy), NUREG-1600. The first apparent

violation involves operator-failures to follow procedures for reactor coolant 1- system baron dilution, watch turnover, adherence to procedures, and prompt 2

reporting of events. As a result of these errors, operators exceeded 1007, reactor power on January 22, 1996. The second apparent violation involves inadequate design control in that the procedure for adding a mixture of i

?

domineralized water and boric acid to the reactor coolant system did not  !

' implement the method stated in the Final Safety Analysis Report (FSAR), and j had not done so since January 1976. The third apparent violation involves a i change that was made to the Unit 1 procedure for reactor coolant syster boron dilution on January 23, 1996, that differed from the method stated in tae )

FSAR, without performing a required safety evaluation.

. No Notice of Violation is presently being issued for these inspection 4 findings. In addition, please be advised that the number and characterization of the apparent violations described in the enclosed inspection report may

-change as a result of further NRC review. ~

A predecisional enforcement conference to discuss these apparent violations a has been scheduled for March 8,1996. Also, you have been requested to bring I

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FPL 2 i the three licensed operators who were involved in the overdilution event to the enforcement conference. The decision to hold a predecisional enforcement i conference does not mean that the NRC has determined that a-violation has occurred or that enforcement action will be taken. This conference is being held to obtain information to enable the NRC to make an enforcement decision,  !

such as a conson understanding of the facts, root causes, missed opportunities  !

to identify the apparent violations sooner, corrective actions, significance of the issues, and the need for lasting and effective corrective action. In j addition, this is an opportunity for you to point out any errors in our '

inspection report and for you to provide any information concerning your )

, perspectives on 1) the severity of the violations, 2) the application of the ,

factors that the NRC considers when it determines the amount of a civil '

penalty that may be assessed in accordance with Section VI.B.2 of the ]

Enforcement Policy, and 3) any other application of the Enforcement Policy to i

! this case, including the exercise of discretion in accordance with Section )

l VII. l You will be advised by separate correspondence of the results of our deliberations on this matter. No response regarding these apparent violations-is required at this time.

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.

O Sir cerel , l l

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Albert F. Gibson, Director Division of Reactor Safety <

Docket Nos. 50-335, 50-389 l License Nos. DPR-67, NPF-16 l

Enclosures:

1. Inspection Report .

2. Enforcement Policy:

Section V, "Predecisional i Enforcement Conferences" cc w/encis:

W. H. Bohlke Vice President

-St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce, FL 34954-0128 cc w/encls cont'd: See page 3 1

- - < _ ~ _ - ,- _, - - - , - ,

FPL 3 cc w/encls cont'd:

l H. N. Paduano, Manager Licensing and Special Programs e Florida Power and Light Company o

P. O. Box 14000 i Juno Beach, FL 33408-0420 -

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9 J. Scarola Plant. General Manager .

St. Lucie Nuclear Plant  ;

P. 0. Box 128 l

Ft. Pierce, FL 34954-0128

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[ E. J. Weinkam Plant Licensing Manager ,

e St. Lucie Nuclear Plant l P. 0. Box 128 '

Ft. Pierce, FL 34954-0218 J. R. Newman, Esq. l Morgan, Lewis & Bockius l 1800 M Street, NW  !

Washington, D. C. 20036 i John T. Butler, Esq. 1 Steel, Hector and Davis j 4000 Southeast Financial Center l Miami, FL 33131-2398 I i

Bill Passetti i Office of Radiation Control Department of Health and )

Rehabilitative Services 1317 Winewood Boulevard

Tallahassee, FL 32399-0700 1 l Jack Shreve Public Counsel Office of the Public Counsel

! c/o The Florida Legislature i 111 West Madison Avenue, Room 812 '

Tallahassee, FL 32399-1400 Joe Myers, Director l Division of Emergency Preparedness l Department of Community Affairs 2740 Centerview Drive Tallahassee, FL 32399-2100 cc w/encls cont'd: See page 4 l

e

i FPL 4 cc w/encls cont'd:

Thomas R. L. Kindred County Administrator St. Lucie County 2300 Virginia Avenue Ft. Pierce, FL 34982 -

4 Charles B. Brinkman

Washington Nuclear Operations ABB Combustion Engineering, Inc.

12300 Twinbrook Parkway, Suite 3300 4 Rockville, MD 20852 I

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p f b% NUCLEAR REGULATORY COMMISSION REGON H 3 $ 101 MARIETTA STREET. N.W. SUITE 2900 7; j ATLANTA, GEORGIA 303D4190

• % ...../

Report Nos.: 50-335/96-03 and 50-389/96-03 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 Inspection Conducted: January 26-30, 1996 Lead Inspector:

R. Sch'in 1 .2 4L Date Signed Reactor Inspector Accompanying Inspectors: B. Desai, Resident Inspector, Turkey Point M. Killer, Senior Resident Inspector, St. Lucie Se' Sandin, Senior Operati~o ns Officer, AEOD

, i/ -Q NdYkb Approved by: '

a.[' ( ~b C.'Casto, Chiel Date Signed Engineering Branch Division of Reactor Safety

SUMMARY

Scope:

This special inspection was conducted on site to review the Unit 1 overdilution event of January 22, 1996.

Inspections were performed during normal and backshift hours and on a weekend.

Results:

The inspectors identified concerns with licensee control of licensed activities and with licensed operator attentiveness. Three related apparent violations were identified:

a. Operators failed to follow procedures, with four examples:

1) Operators failed to stop dilution of the reactor coolant system when the proper amount of demineralized water had been added.

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! -2) There was inadequate watch turnover for the operator at the controls during dilution.

! 3) Operators performed the boron dilution procedure from memory, without referring to the procedure, and without strictly adhering to' i j the procedure.- -

) 4) Operators failed to promptly verbally report the event to licensee j management.

! As a result of these errors, operators exceeded 100% reactor power. This  !

3 event was bounded by the'FSAR Chapter 15 accident analysis. l 1 '

Design control was inadequate, in that Unit I procedures for a.iding a

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mixture of domineralized water and boric acid to the reactor coolant.

i system (in manual and directly to the' suction of the charging pumps) did j

! not implement the method stated in the Final Safety Analysis Report I' (FSAR), Chapter 15 (in automatic and to the volume control tank), and had i not done so since January 1976, before Unit I was licensed.

c. A 10 CFR 50.59 evaluation was inadequate, in that the licensee made a i cha'nge to the Unit 1 boron dilution procedure on January 23, 1996 (after l the event), to allow adding demineralized water in " Manual" and directly to the suction of the charging pumps, that was different from the method '

stated in the FSAR, Chapter 15 (in " Dilute" and to the volume control '

tank) and without preparing a 10 CFR 50.59 safety evaluation.

In addition, a weakness in control room command and control was identified, with the following examples: 3

a. The senior reactor operator (SRO) in the control room was not aware of the. boron dilution in progress.

b. The board operator did not inform the SRO of the boron dilution - this l was.a general practice at the site and not required by procedures.

c. The watchstander board in the Unit I control room was not maintained (on Saturday, January 27).

d. The SRO_ in the control room was allowed by procedures to be in the Assistant Nuclear Plant Supervisor's (ANPS) office for unlimited time, out of sight of control room activities and out of hearing range of i almost all control room activities except annunciator alarms. (During  ;

this event, the control room SRO was at the control room desk operator's 1 area and in sight of control room activities.)

Also, a weakness in procedures was identified, with the following examples:

a. The procedure change process failed to address deficiencies in the Unit 1 procedure at_the time the Unit 2 procedure was changed. During the I

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, event, manual boron dilution as performed by operators could not be i accomplished by strict compliance with the Unit 1 procedure.

b. Procedures did not require the operator at the controls to remain by the

dilution controls during a manual boron dilution. i

. There was also an identified weakness in corrective action, with the following examples:

I

a. The licensee's initial investigation of the event was not thorough.

1 Spe'cifically, the initial investigation concluded that maximum reactor power was 100.2%, but subsegur.nt review by the NRC and licensee found that maximum reactor power was approximately 101.18%. The licensee's initial investigation alsc did not identify that the reactor operator who

! started the boron dilution had left the control room with the dilution in l progress and without telling other operators that a dilution was in  !

progress.

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.b. The revised procedure for manual baron dilution (after the event) did not require the operator at the controls to remain by the dilution controls

, during a manual boron dilution.

Further, there was an identified weakness in operating experience feedback:

a. In response to.Significant Operating Events Report 94-02, dated September 1994, which described a similar Turkey Point overdilution event, the licensee reviewed the St. Lucie operating procedures related to boron dilution and concluded that no changes were needed. This was a missed opportunity to strengthen operating procedures to prevent the January 22, 1996, overdilution event. -

The inspectors also had the following comments:

a. There was no clearly noticeable indication of boron dilution in progress.

The dilution clicker was quiet (and possibly inaudible from the desk area) and sounded identical to other nearby clickers that routinely made noise.

b. No alarms came in during this event to alert the operators that reactor .

coolant system cold leg temperature (Tc) and reactor power had exceeded allowable values. The licensee had raised the Tc alarm setpoint so that it no longer served to alert operators that they had entered a Technical Specification two-hour action statement. Also, control room operators did not have complete information available about the Digital Data 1 Processing System computer alarms.

c. Operators routinely did not log reactivity additions; however, the licensee's Conduct of Operations procedure stated that operators should log significant reactivity changes.

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TABLE OF CONTENTS I

1. Persons Contacted . . . . . . . . . . . . . . . . . . . . . . . . .

1

2. General Description of the Overdilution Event . . . . . . . . . . . 1

. 3. Detailed Sequence of Events . . . . . . . . . . . . . . . . . . . . 2

4. Shift Hanning, Operator Qualifications, and Overtime . . . . . . . 4 ,

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4.1 Adequate Shift Manning . . . . . . . . . . . . . . . . . . . . 4 l l

l 4.2 Adequate Operator Qualifications . . . . . . . . . . . . . . . 5 4.3 Adequate Overtime Use . . . . . . . . . . . . . . . . . . . . 5 l 1

4.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . 6 l

5. Operating and Administrative Procedures . . . . . . . . . . . . . . 6 5.1 Inadequate Boron Dilution . . . . . . . . . . . . . . . . . . 6 5.2 Inadequate Watch Turnover . . . . . . . . . . . . . . . . . . 6 5.3 Inadequate Adherence to Procedures . . . . . . . . . . . . . . 7 5.4 Inadequate Prompt Notification . . . . . . . . . . . . . . . . 8

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1 5.5 Weakness in Control Room Command and Control . . . . . . . . . 8 1

5.6 Weakness in Operating Procedures . . . . . . . . . . . . . . . 9 l 5.7 Other Comments . . . . . . . . . . . . . . . . . . . . . . . . 9 (

5.8 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . 10

6. Updated Final Safety Analysis Report Review . . . . . . . . . . . 10 6.1 Intdequate Design Control . . . . . . . . . . . . . . . . . . 10

)

i 6.2 Inadequate 10 CFR 50.59 Evaluation . . . . . . . . . . . . . 12 6.3 Licensee Dissenting Comments . . . . . . . . . . . . . . . . 13 6.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . 14

7. Human Factors and Equipment Condition . . . . . . . . . . . . . . 14 7.1 Control Room Arrangement . . . . . . . . . . . . . . . . . . 14 7.2 Water Flow Totalizer and Batch Integrator . . . . . . . . . . 14 I

7.3 A l a rm s . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 l

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, 7.( Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . 15

8. Operating Experience Feedback . . . . . . . . . . . . . . . . . . .

16 2

8.1 -Turkey Point Overdilution Event . . . . . . . . . . . . . . . 16 l 8.2 St. Lucie Inadvertent Dilution Event . . . . . . . . . . . . 17 )

8.3 Conclusions . . . . .-. . . . . . . . . . . . . . . . . . . . 17  :

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9. Management Expectations . . . . . . . . . . . . . . . . . . . . . 17 L

9.1 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . 18

10. Initial Corrective Actions . . . . . . . . . . . . . . . . . . . . 18 10.1 Weakness in Initial Event Investigation . . . . . . . . . . . 18 10.2 Corrective Actions . . . . . . . . . . . . . . . . . . . . . 18 10.3 Licensee Dissenting Comments . . . . . . . . . . . . . . . . 19-10.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . 19

11. ' Exit Interview . . . . . . . . . . . . . . . . . . . . . . . . . . 19

12. Abbreviations, Acronyms, and Initialisms . . . . . . . . . . . . . 19 1 1

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R'EPORTDETdILS NOTE: Acronyms used in this report are defined in paragraph 12.

1. Persons contacted Licensee Employees

• B1adow,~W., Site Quality Manager ,

1. Bohlke, W., St. Lucie Plant Vice President

• Bdrton, C., Site Services Manager

• Dawson,'R., Licensing' Manager

• Denver, D., Site Engineering Manager

• Fincher, P., Training Manager

• Fulford, P.,' Operations Support and Testing Supervisor

• Marchese, J., Maintenance Manager

• Olson, R., Instrument and Control Maintenance Supervisor

1. Plunkett, T., incoming President - Nuclear Division

• Sager, D., St. Lucie Plant Vice President

• 1. Scarola, J.. St. Lucie Plant General Manager .

• 1. Weinkam, E., Licensing Manager

• West, J., Operations Manager

• Wood, C., Operations Supervisor j

Other licensee employees contacted included office, operations, engineering, maintenance, chemistry / radiation, and corporate personnel.

NRC Personnel

1. C. Casto, Branch Chief, Division of Reactor Safety, RII

• B. Desai, Resident Inspector, Turkey Point

1. K. Landis, Branch Chief, Division of Reactor Projects, RII

• M. Miller, Senior Resident Inspector, St. Lucie

• R. Musser,. Resident Inspector, Browns Ferry

• S. Sandin, Senior Operations Officer, AEOD l

• 1. R. Schin, Reactor Inspector I

• Attended exit interview on January 30, 1996.

1. Attended exit interview on February 8, 1996.

2. General Description of the Overdilution Event (92700)

At approximately 2:25 a.m. on January 22, 1996, the Unit I control board RCO began a manual boron dilution of the RCS by aligning primary makeup water (demineralized water) directly to the suction of the IB Charging Pump. Moments after beginning the dilutitin, the Board RCO responded to a secondary plant annunciator and then saw the Desk RCO return from the kit'chen. He requested that the Desk RCO relieve him so that he could prepare his meal. During the turnover, there was no discussion of the dilution in progress. Following the turnover, the relief operator at the i controls and the 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

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other RCO of the overdilution, which was overheard by the NPS, and stopped the dilution. The NPS directed the ANPS to take charge and begin a manual boration. Unit 1 entered two-hour TS LCO Action Statement 3.2.5 for Tc greater than ;549'F. The maximum Tc obtained was 549.9'F and the maximum reactor power was 101.18%. Tc was above the TS limit of 549'F for approximately 50 minutes and reactor power was above 100% for approximately 70 minutes. The operators did not promptly verbally notify  ;

plant management or the.NRC of this event. During this event, the TS LCO  :

Action Statement for Tc was not exceeded and th:: giNance of the NRC l memorandum from E. L. Jordan of August 22, 1930, on maximum reactor power  ;

was not exceeded.. Also, this event was bounded by the FSAR Chapter 15

- accident analysis. ,

3. Detailed Sequence of Events (92700)  ;

See Attachment.1 for the Unit I control room arrangement and locations of operators. Also, note that the times in the sequence of events are -

approximations and only relevant events are mentioned.

1/21/96 3 11:00 p.m. Incoming mid shift assumed Unit I responsibility with the Unit at 100% power, 870 MWe, Tavg at 575 degrees F, Th at i 600 degrees F, Tc at 548.9 degrees F, RCS Boron ,

concentration at 376 ppm, Xe worth at -2722 pcm, all CEAs  !

fully withdrawn and in 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 w u intermittently t coming in due to a failed pressure ssitch. ,

. 11i45 p.m. Board RCO reset to zero the primary water (to VCT or  ;

charging pump) flow totalizer in preparation for inventory balance (RCS leak rate calculation). '

11:00 p.m.-

2:00 a.m. Board RCO recalled performing at least two RCS boron dilutions of approximately 35 gallons each between 11:00 '

p.m. and 2:20 a.m. without resetting the totalizer.

1/22/96 i

2:00 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.

2:10 a.m. ANPS turned over control room senior reactor operator i responsibility to NPS and proceeded to the kitchen to  ;

,. prepare meal. l e

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l 3 l l 2:15 a.m. Desk RCO left the 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 l allowable program value-of 549.0 degrees F. l l

i 2:23 a.m. Desk RCO arrived in the control room with his meal. l

. l 2:25 a.m. Board RCO began a manual dilution by aligning primary I i

water to the suction of the charging pumps, by opening FCV-2210X and A0V-2525. The flow rate was approximately 44 gpm.

2:26 a.m. Annunciator E-9 associated with circulatlng water pump lube water supply strainer high delta P was received. The Board RCO walked to the panel and acknowledged the annunciator.

l 2:27 a.m. After acknowledging the annunciator, the Board RCO decided l to proceed to the kitchen to prepare his meal. The Board  ;

RCO conveyed this to the Desk RCO and requested that he take over the ' operator at the controls' responsibilities.

However, he did not mention the ongoing dilution. The  !

Desk RCO got up and proceeded to the board in the vicinity of RTGB 103. The original Board RCO proceeded to the

, kitchen and started preparing his meal. At this time, the NPS and the STA were in tne 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.

2:35 a.m. The original Board RCO 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 i securing the dilution. The Desk RCO questioned how much i water was added and the Board RCO noted from the totalizer that approximately 400 gallons was added.

2:35 a.m. Soon after, annunciator M-16 associated with RCP l controlled bleedoff pressure high was received. At this point, the Tc was noted by the Desk RCO to be 549.6 degrees F. Entry into the two-hour action statement associated with TS 3.2.5, DNB parameters, was recognized and later logged.

2:36 a.m. Desk RCO directed the Board RCO to initiate baration to restore Tc to program. The NWE calculated the amount of borated water to be added to the RCS. The NPS asked the Desk RCO to notify the unit ANPS to come to the control room.

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4 2:40 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%

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E:50 a.m. Operators secured boration. )

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14 a.m. Tc noted below 549.0 degrees.F. TS Action Statement was l

exited. ,

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3:45 a.m. STA initiated an In-House Event' Report and notified HPES i personnel by telephone. I i' 5:45 a.m.- NPS informed Operations Supervisor of the overdilution during.a routine morning phone call.

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45 a.m.-

6:00 a.m. Shift turnover occurred. The dilution event was  !

apparently not discussed with the oncoming shift. j

6:25 a.m. In-House Event Report was E-mailed to standard distribution, which included plant management, by the STA.

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6:30 a.m. Operations Manager toured the control room but was not informed of the overdilution event.

7:20 a.m. Operations Manager read the control room logs (in his office 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.

7:45 a.m. Senior plant management discussed the event during the morning meeting.

10:00 a.m. NRC resident inspector was given the event report that was initiated associated with the event.

4. Shift Manning, Operator Qualifications, and Overtime (92700) 4.1 Adequate Shift Manning The inspectors reviewed actual shift manning as compared with TS l requirements. TS Table 6.2-1 establishes the minimum shift crew i composition for St. Lucie Unit 1. With both Unit 1 and Unit 2 operating l in a mode 1 condition, a Unit SRO, two R0s, and two A0s are required for each unit. In addition, a Shift Supervisor (SRO) and an STA are required, who may be the same individuals for both units. Additionally, ,

although not required by TS, an NWE (SRO) was assigned to support both units. At any time, at least one R0 (at the controls) and one SRO l

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(control' room comm nd function) are required to be in the Unit I control room.

During the event, operators on shift included an NPS (SRO), who was at a

j. desk in the Unit 1 control room (fulfilling the control room command i function); an ANPS (SRO), who was in the kitchen near the Unit I control room until summoned to supervise restoration of Unit I reactor power and j

reactor coolant system cold leg temperature; a Board RCO (RO) who started the boron dilution (while at the controls) and then went to the kitchen after being relieved at the controls by the Desk RC0; a Desk RCO (RO) who relieved the Board RCO at the controls; an NWE (SRO), who was in the NWE office in the Unit I control room; and an STA, who was in the Unit I control room near the NPS. The Unit 1 control room arrangement and operator locations are shown .in Attachment 1. The inspectors concluded that the TS requirements for shift manning and the minimum number of operators in the control room were satisfied.

4.2 Adequate Operator Qualifications 1

The inspectors reviewed,the' Unit I licensed shift crew qualifications, I medical status, and experience. All licensed operators had a current license and medical certification on file. The dates of initial R0 and SRO licenses and most recent requalifications were as 'follows:

R0 (initiall SRO (initial) Reaualification NPS March 1985 September 1988 November 1995 ,

ANPS August 1984 September 1988 December 1995 Board RCO November 1993 N.A. November 1995 Desk RCO May.1992 N.A. October 1995 NWE May 1987 November 1991 December 1995 The inspectors concluded that the qualification status of the Unit I licensed operators was current and that the operators had considerable operating experience.

4.3 Adequate Overtime Use The inspectors reviewed the operators' recent work history (including ,

overtime) and alertness. St. Lucie shift crews worked a forward rotation i schedule consisting of:

e Seven Peak shifts (1500-2300) Monday through Sunday, I e Seven Mid shifts (7.300-0700) Wednesday through Tuesday, o Six Day shifts (0700-1500) Friday through Wednesday, followed by e Five Day shifts (0700-1500) in either a relief capacity or in requalification training before beginning Peak shift the following Monday.

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On the morning of January 22. the Unit I crew was working their sixth consecutive mid shift. The inspectors questioned the RCOs to determine whether fatigue may have affected their alertness. Both RCDs said they

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, 6 l were Alert and rested. The NE and STA confirmed this.. The inspector reviewed the Operations Overtime Tracker sheets which showed that the licensee had been tracking overtime to assure compliance with TS 3 requirements. During the week prior to the event, some Unit 1 shift crew i

members had stood a double shift (two consecutive eight-hour shifts plus 1 one-half hour turnover, followed by seven and one-half hours off, followed by an eight-hour shift), but all Unit 1 shift crew members had complied with the TS 6.2.2.f requirements for maximum working hours. The inspectors concluded th.at neither excessive overtime nor operator fatigue con,tributed~to this event.

) 4.4 Conclusions

! The inspectors concluded that TS requirements for shift manning and minimum number of operators in the control room were satisfied. Also, i

the qualification status of the Unit I licensed operators was current and 4

those operators had considerable operating experience. In addition, neither excessive overtime nor operator fatigue contributed to this event.

4 i 5. Operating and Administrative Procedures (92700)

!- The inspectors reviewed operator actions related to this event and the licensce's related operating and administrative procedures.

5.1 Inadequate Boron Dilution Operating Procedure No. 1-0250020, Boron Concentration Control - Normal Control, Rev. 35, established a method to supply boric acid and makeup water to the RCS at a desired boron concentration and provided instructions for various modes of control. The Board RCO had used.

procedure section 8.5, Manual Mode of Operation, to initiate the boron dil-ution. Procedure step 8.5.14 required that operators monitor the i boric acid and water flow totalizers and, when the desired amounts had 1 been added. cicse valve V2525 or V2512, as applicable, to stop the addition of boric.at.id and primary makeup water. . The Board RCO desired to add between 25 and 40 gallons of primary makeup water, but failed to stop dilution until approximately 400 gallons were added. During this time, the temporary relief operator at the controls was unaware that a boron cancentration dilution was in progress, which resulted in an unmonitred r". activity addition. The SRO and other operators in the control room were also unaware that a reactivity addition was in progress. This failure to follow OP 1-0250020 requirements, to monitor and stop the dilution when the desired amount was added, is an example of apparent violation 50-335,389/96-03-01.

5.2 Inadequate Watch Turnover Administrative Procedure No. 0010120, Conduct of Operations, Rev 79 Appendix D Crew Relief / Shift Tumover, required that, for short term watchstander relief, a turnover be conducted that include: general

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l concentration dilution was in progress. As a result, the relief operator I at the controls was unaware that a boron concentration dilution was in progress and failed to adequately monitor and control the dilution. This i failure to follow AP 0010120 requirements, for a short term watchstander j relief, is a second example of apparent violation 50-335,389/96-03-01.

i The inspectors questioned both RCOs as to how they typically conducted short term watchstation turnovers and, more specifically, what occurred during this event. The Board RCO said that he recalled responding to a recurring annunciator alarm E-9 moments after starting _ the dilution. He moved from the charging station at RTGB-105 to RTGB-102. He did not

, recall how long he was at RTGB-102 before seeing the Desk RCO returning from the kitchen. He left RTGB-102 by stating "I will be over the line. i I am going to get my food" (over the line refers to the boundary within which the operator at the controls must remain). The Desk RCO acknowledged, assumed operator at the controls responsibility, and moved i 4

from behind the desk to a position in front of RTGB-103. None of the short term relief requirements were performed prior to notifying the NPS I of the watchstation turnover. The Board RCO stated that it was a general  !

practice, and management's expectation, to inform his relief of any evolutions. maintenance, or work in progress. Typically, this would not involve a face-to-face board walkdown. In this particular event, the Board RC0 felt he was distracted by the E-9 annunciator alarm; however.

he had no explanation of why he lost track of the dilution. The Desk RCO i confirmed the general practice and management's expectation regarding short term relief. He further said that he did not ask the Board RCO for  !

the status of the watchstation based on:

His past experience and expectation that the operator requesting relief would provide the information routinely, and His observation that the annunciators were " black board" and his knowledge that there was no maintenance or other activities scheduled for that shift.

The inspector discussed the Desk RCO's performance in short term shift relief with both the Operations Supervisor and Operations Manager and concluded his performance was consistent with past practices and man,agement's expectations.

5.3 Inadequate Adherence to Procedures Administrative Procedure No. 0010120, Appendix M, Procedural Compliance and Implementation, stated: " Controlled procedures are available in both Control Rooms and shall be implemented and complied with in accordance with the instructions provided in QI 5-PR/PSL-1." Procedure QI 5-PR/PSL-1, Preparation, Revision, Review / Approval of Procedures, Rev 67, Section 5.13.2, stated "A strict adherence to procedural requirement - Verbatim

. 8 Compliance - is the policy expected and required of all St. Lucie Plant personnel." AP 0010120, Appendix M, also identified those tasks considered " skill of the trade" which were repetitive and routine in nature and may be performed from memory without referring to the procedure.

Boron concentration control was not identified as one of these tasks. The inspectors determined during interviews that both RCOs, the NWE'. and the Operations Supervisor mistakenly believed that OP 1-0250020, Boron Concentration Control, was a " skill of the trade" task. During this event, the Board RCO had started the boron dilution from memory without referring to the procedure.

OP 1-0250020,' Section 8.5, provided steps for adding a blend of boric acid and primary water to the VCT or directly to the suction of the charging pumps. It did not. describe adding primary water with no boric acid. It included steps for starting a boric acid makeup pump and opening the boric acid makeup isolation. valve and those steps were not indicated as optional. During this event, the Board RCO did not strictly adhere to OP 1-0250020 in that he added primary makeup water with no boric acid, did not start a boric acid makeup pump, and did not open the boric acid makeup isolation valve. Operator performance of OP 1-0250020 from memory, without referring to the procedure, and without strictly adhering to the procedure (as required by AP 0010120), is a third example of apparent violation 50-335,389/96-03-01.

5.4 Inadequate Prompt Notification The inspectors noted that AP 0010120, Appendix E, Notification of Operations Supervisor /FPL Management, required prompt verbal notification

-to the Operations Supervisor of unplanned reactivity changes. However, on January 22, 1996, between 2:30 a.m. and 7:20 a.m., operators failed to give prompt verbal notificatit,n to the Operations Supervisor of unplanned

! reactivity changes that had occurred during the overdilution event. In

{ addition, the Operations Manager toured the Unit I control room at i 6:30 a.m., but control room operators did not inform him of the i overdilution event. It was not until about 7:30 a.m., when the

1. ~

Operations Manager and the Plant General Manager read the operator logs on their office computers, that plant management became aware of the overdilution event. The failure of operators to follow requirements of i AP 0010120, for prompt verbal notification to the Operations Supervisor i

of unplanned reactivity changes, is a fourth example of apparent violation 50-335,389/96-03-01.

4 5.5' Weakness in Control Room Command and Control During this event, the Board RCO did not inform the NPS that he was-

beginning a boron dilution. Operators told the inspectors that not 4

notifying the SRO about baron dilution was a general practice at the site. Also, licensee procedures did not require the Board RCO to notify j the SRO about starting boron dilution. In addition, during this event j the NPS was not aware that a baron dilution was in progress. The 4

inspectors identified that the Board RCO not telling the NPS about a boron dilution in progress and the NPS not being aware that a boron i

i p , - --

---g-w-., -

9 4

dilution was in progress were examples of a licensee weakness in control room command and control.

A review of licensee procedures revealed that the control room SRO was allowed to be to be in the ANPS office for an unlimited time, out of sight of control room activities and out of hearing range of almost all control room activities except annunciator alarms. The SRO was not in the ANPS office during this event and the inspectors did not identify any 4

examples where the SRO spent excessive time in the ANPS office.

Nonetheless, the inspectors identified the fact that licensee procedures allowed the SRO to bc in the ANPS office for an unlimited time as another example of a licensee weakness in control room command and. control.

While visiting the Unit I control room on Saturday, January 27, the inspectors noted that the watchstander board on the wall of the control room was not maintained current. The watchstander names indicated on the board were not those of the crew that was currently on watch. The inspectors identified this as another indication of a licensee weakness in command and control.

5.6 Weakness in Operating Procedures The Operations Manager and other licensed operators told the inspectors that boron dilution by adding primary water with no boric acid, in manual and directly to the suction of the charging pumps, had been performed by operators for many years and was the routinely used method. The inspectors inquired as to how operators could use OP 1-0250020 to do this while following the verbatim compliance policy. The Technical Operations Supervisor noted that this procedural deficiency had been identified on Unit 2 and corrected prior to restart in January 1996. He further said that usually when a deficiency of this nature is noted, the other Unit's procedures are reviewed and corrected, if applicable. However, in this case, he was surprised to see that it had not been done. The inspectors reviewed the Unit 2 procedure change and verified that it had failed to include changing the Unit 1 procedure. The inspectors identified this failure to address the Unit 1 procedure when the Unit 2 procedure was changed as an example of a weakness in licensee procedures.

The inspectors noted that licensee procedures in effect during this 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 Boron dilution added reactivity to the nuclear reactor, albeit sbwer than control rod movement, but was not administratively controlled in the same manner as was control rod movement. The inspectors considered the lack of a requirement for the Board RCO to remain at the dilution controls during a boron dilution to constitute another example of a weakness in licensee procedures.

5.7 Other Comments The inspectors also noted that operators did not routinely log reactivity additions by boron dilution. However, AP 0010120, Appendix F, Log

4 i

10 Keeping, stated that RCO log entries should include significant changes

in plant conditions, including reactivity changes.

5.8 Conclusions In conclusion, the inspectors identified an apparent violation for  :

' operator failures to follow procedures, with four examples: 1) Operators failed to stop dilution of the RCS when the proper amount of l demineralized water had been added; 2) There was inadequate watch j

turnover for the operator at tne controls during dilution; 3) Operators '

performed the boration dilution procedure from memory, without referring l to the procedure, and without strictly adhering to the procedure; and 4)'

Operators failed to promptly verbally report the event to licensee management. As a result of these errors, operators exceeded 100% reactor power.

The inspectors also identified four examples of a weakness in licensee control room command and control: 1) The Board RCO did not tell the NPS about a boron dilution in progress: 2) The NPS was not aware that a boron dilution was in progress; 3) 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 4) The control room watchstander board was not maintained current.

In addition, the inspectors identified two examples of a weakness in licensee procedures: 1) The p ocedure change process had failed to address deficiencies in the Unit 1 procedure when the Unit 2 procedure was changed, and 2) Procedures did not require the Board RCO to remain at

, the dilution controls during a boron dilution.

The inspectors also had the following comment: Operators routinely did not log reactivity additions; however, the licensee's Conduct of Operations procedure stated that operators should log significant reactivity changes. l l

6. Updated Final Safety Analysis Report Review (92700) f A recent discovery of a licensee operating their facility in a manner contrary to the UFSAR description highlighted the need for a special focused review that compares plant practices, procedures, and/or i parameters to the UFSAR description. The inspector reviewed applicable  ;

sections of the St. Lucie UFSAR, including System Description, Chapter  !

9.3.4, and Accident Analysis, Chapter 15.2.4, to verify current plant configuration, procedures, and operating practices conformed to UFSAR l description and commitments as well as to determine significance of the i dilution event in reference to the assumptions in the accident analysis.

6.1 Inadequate Design Control The inspector noted inconsistencies between the wording of the UFSAR and l plant procedures. UFSAR Chapter 9.3.4.2.1, Chemical and Volume Control l

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1 1

1 11 Syrtem Normal Operation, described the four modes of makeup to the RCS

, affecting boron concentration: dilute, borate, manual, and automatic.

The UFSAR stated that in the dilute mode, a preset quantity of reactor i makeup water is added into the VCT at a preset rate. It stated that the 1

manual mode is primarily used for makeup and filling the safety injection '

j tanks and the refueling water tank. -

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UFSAR Chapter 15.2.4.1, Chemical and Volume Control System Malfunction-Boron Dilution Event, stated-Boron dilution is conducted under strict administrative procedures

, which specify permissible limits on the rate and magnitude of any  :

rcraired change in boron concentration. . . . During normal l l r- ration, concentrated boric acid solution is mixed with

% mineralized makeup water to the concentration required for proper plant operation and is automatically introduced into the volume i control tank in response to a low water level signal from the volume control. To effect boron dilution, the makeup controller mode

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selector switch must be set to " Dilute" and the demineralized water i batch quantity selector set to the desired quantity. When the  ;

[ specific amount has been injected, the demineralized water control valve is shut automatically. . . . . Because of the procedures )

involved and the numerous alarms and indications available to the

operator, the probability of a sustained or erroneous dilution is

,! very low. i However, the inspectors noted that procedure OP 1-0250020, Boron

, Concentration Control - Normal Control, Rev. 35, that was in effect  ;

during the event, allowed adding a mixture of boric acid and primary i

water in manual and directly to the suction of the charging pumps. It j j did not include baron dilution by adding primary water, with no boric l

acid, in the manual mode of operation.

The inspectors also noted that, during the event, no alarms came in to

alert operators of the overdilution. Just after the Board RCO recognized the overdilution and initiated corrective actions, annunciator M-16 associated with RCP controlled bleedoff pressure high alarmed. That alarm, which was not mentioned in the UFSAR, came in because the RCP bleedoff went to the VCT, where the pressure had increased due to the

); increased level from primary water addition. The alarms that were credited in the UFSAR did not come in during this event, in part, because the dilution path was directly to the suction of the charging pumps and 4

not to the VCT. '

, Further review, as requested by the inspectors, found that the first time the' dilution procedure had been changed to allow adding a mixture of l primary water and boric acid in manual and directly to the suction of the

, charging pumps was in a change to rev. 2 of the procedure, dated i January 24, 1976, before the Unit 1 operating license had been issued.

I Tha UFSAR Chapter 15.2.4.1 description of the methods for adding a mixture of primary water and boric acid and for boron dilution, as stated

.i above, was on UFSAR pages 15.2.4-1 and 15.2.4-2, which were original I

h mes> v

. .. . l 8  :

12  !

pages - the words remained exactly as reviewed by. the NRC, as part of the l

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~ design basis as specified in the license application, prior to Unit 1 licensing. The inspectors cencluded _that the licensee's procedures, for l

, adding a mixture of boric acid and primary water to the RCS, differed '

from the' methods described in the UFSAR from January 24, 1976, through i January 23, 1996. -

i 10 CFR 50, Appendix B, Design Control, requires that measures be l established to assure that applicable regulatory requirements and the design basis, as specified in the license application, are correctly translated into procedures. The inspectors concluded that the UFSAR .

1 description of methods for adding boric acid and primary water to the RCS l i

had not been correctly translated into procedures. This is identified as

. apparent violation 50-335,389/96-03-02: FSAR Description of Methods of 1-f RCS Boron Dilution Not Correctly Translated into Procedures.

6.2 Inadequate 10 CFR 50.59 Evaluation The inspectors reviewed TC 1-96-017, dated January 23, 1996, which i

revised OP 1-0250020, Rev. 35, on_the day after the overdilution event.-  ;

The TC stated that the reason for the change was to add procedural guidance for manual dilution and boration of the RCS, in the same format as the corresponding Unit 2 procedure. The inspectcrs noted that in the-10 CFR 50.59 screening that was performed for the TC, the question "Does the change represent a change to procedures as described in the SAR" was answered "No." Consequently, a 10 CFR 50.59 safety evaluation was not performed. The contents of the change included a new two-page step by 4 step instruction on manual dilution and a new three-page instruction on manual boration. The new instruction on manual dilution allowed dilution in manual and directly to the suction of the charging pumps. The inspectors concluded that the TC was a change to the procedure r.nd that the method of dilution described in the TC (in " Manual" and direct to the suction of the charging pumps) was different from the method of dilution described in the UFSAR (in " Dilute" and to the VCT).

10 CFR 50.59 states that the licensee may make changes in the procedures as described in the SAR, without prior Commission approval, unless the proposed change involves an unreviewed safety question. A proposed l

change shall be deemed to involve an unreviewed safety question if the probability of occurrence of an accident 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 these changes constitute changes in procedures as described in the SAR, and the records must include a written safety evaluation that provides the basis for the determination that the change does not involve an unreviewed safety question. In this case, the licensee had no written safety evaluation.

The licensee's failure to perform an adequate 10 CFR 50.59 evaluation for TC 1-96-017 is identified as apparent violation 50-335,389/96-03-03; Change to Procedure as Described in FSAR Without a Safety Evaluation.

13-6.3 Licensee Dissenting Comments The licensee had dissenting comments with regard to the apparent 10 CFR 50.59 violation. The dissenting comments, from the Engineering Mantger and the Licensing Manager, were:

a.< The previous procedure allowed dikuting in manual and directly to the suction of the charging pumps, and that had been the practice for many years. Therefore, the TC on January 23., 1996 (after the event) did not change the method of dilution, but only clarified a previously existing procedure and made it confore to " verbatim ,

compliance" rules.-

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.

c. The accident analysis assumed a worst case dilution event with domineralized water going directly to the suction of the charging pumps and three charging pumps running. That would be three times the flowrate of this event and therefore that analysis bounds this event.

d. The FSAR Chapter 9 descript', i the Chemical and Volume Control System did not prohibit dilutt. in manual and directly to the suction of the charging pumps.

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.

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.

g. Since the operating procedure that was in effect at the time the operating license was issued allowed dilution in manual and directly to the suction of the charging pumps, that method was included in the original licensing basis of the plant.

After receiving these licensee comments, the inspectors' concern remained  !

unchanged: TC 1-96-017 of January 23, 1996 (after the event) described procedure steps for dilution in manual and directly to the suction of the a 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 i

shutoff. The licensee had not performed a safety analysis of this i difference and had not revised the procedure and/or FSAR to make them agree.

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, 14 6.4 Conclusions j~ The inspectors concluded that licensee design control was. inadequate, in that Unit 1 procedures for adding a mixture of domineralized water and boric-acid to the reactor coolant system (in manual and directly to the ,

suction of the' charging pumps) did not-implement the procedure as stated in the FSAR, Chapter 15 (in automatic and to the VCT) and had not done so j since January 1976, before Unit I was licensed.

). The inspectors also concluded that a 10 CFR 50.59 evaluation was j

inadequate, in that the licensee made a change to the Unit I dilution

! procedure on January 23, 1996 (after the event), to allow adding pure i

domineralized water-in " Manual" and directly to the suction of the charging pumps,.that was different from the procedure as stated in the FSAR,. Chapter 15 (in " Dilute" and to the VCT) without a 10 CFR 50.59

! safety evaluation.

s

7. Human Factors & Equipment Condition (92700)

! The inspectors reviewed control room layout including operator desks, 1

ANPS office, and kitchen location; as well as system and annunciator panels, controls, and indications to assess their potential contribution i

to the overdilution event. A plan view of the Unit I control room layout

is included as Attachment 1. The inspectors had the following observations in this area:

{ 7.1 Control Room Arrangement The~ location of the operators' desks where the STA, NPS, and desk '

operator were seated were within visual and audible range of all significant alarms and indications and did not compromise the operators' ability to react to an abnormal. condition or indication.

4 1

The location of the ANPS office (where it was acceptable for the ANPS to perform administrative tasks) was not within the visual range of the

' control room panels and indications but was within audible range of most annunciator alarms. This did not contribute to the overdilution event as the control room SRO responsibility was fulfilled by the NPS who was

' seated at a desk in the control room during the overdilution event.

Further, the inspectors were informed by the licensee that-the ANPS 4

routinely spends a majority of his/her time in the control room outside the office, i.e. in the controls area. The inspectors were informed i

that, after the overdilution event, the licensee was considering relocating the ANPS work area / office to within the controls area of the control room.

7.2 Water Flow Totalizer and Batch Integrator i- The inspectors noted that there was no clearly noticeable indication in 1

the control room of dilution in progress. The dilution water flow totalizer clicker was quiet (and possibly inaudible from the desk area),

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i 15 i

sounded identical to the nearby clickers from the waste gas and liquid release totalizers that routinely made noise, and was masked by noise from the control room air conditioning units. i i.

! Operators stated that the makeup water batch integrator that was designed to enable automatic makeup had not been used in the last several years.

The inspectors noted that there was no open work request on the makeup water batch integrator.

7.3 Alarms The annunciator panel ar.d DDPS (computer) alarm setpoints associated witli 3

Tc had oeen modified from 549 degrees F to 552 degrees F for the l annunciator panel and 551 degrees F for DDPS. The inspector reviewed and ,j discussed the modification with the licensee. The licensee operated the i i plant with Tc close to 549 degrees F for thermal efficiency purposes.

With the alarm set at 549 degrees F, the annunciator would often alarm,

becoming a nuisance to the operators. Also, the alarm would at times remain locked in, thereby becoming unavailable for future use..

! Therefore, the licensee raised the setpoint sufficiently so that the-1 alarm would not routinely come in. The inspector concluded that, while the decision to raise the alarm setpoints might have seemed reasonable, the alarms no longer functioned to alert the operators when.they were

exceeding the TS limit on Tc of 549 degrees F and entering a two-hour

action statement. i 1

V The inspectors asked if there were any other alarms or indications that i

would alert the operator of an overdilution event, and the licensee indicated that there was a delta T power alarm on the DDPS computer, set

! at 101 percent power. Since 101 percent power had been exceeded during this event and that alarm had not ccme in, the inspectors asked the licensee to verify the alarm setpoint and functionality. . Upon investigation, the licensee determined that the DDPS delta T power Unit 1 alarm setpoint was 101 percent and Unit 2 setpoint was 150 percent.

However, these alarms were not in use and were disabled. The inspectors concluded that control room operators and other licensee personnel did i not have complete information available about DDPS computer alarms.

l The licensee informed the inspectors that a feedwater high temperature  !

alarm, set at 437 degrees F, would come in at approximately 102 percent power. Also, the Tc alarms would have come in at 551 and 552 degrees F to alert the operators of a more severe transient than the one that occurred on January 22, 1996.

7.4 Conclusions The inspectors concluded that the control room arrangement did not contribute to the overdilution event. However, the location of the ANPS office was previously addressed as an example of weakness in control room comand and control.

_ _ . _ _ _ _ _ _ . . _ _ _ . . _ . . _ _ _ _ . ~ _ _ ___

, 16 i The inspectors noted that there was no clearly noticeable indication of dilution in progress. The dilution clicker was quiet (and possibly j inaudible from the desk area) and sounded identical to the nearby.

, clickers that routinely made noise.

The inspectors also noted that no alares came in during this event to

alert the operators that Tc and reactor power had exceeded allowable

values. The licensee had raised the Tc alarm setpoint so that it no longer served to alert operators that they had entered a TS two-hour action statement. Also, control room operators did not have complete

] information available about the DDPS computer alarms.

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8. Operating Experience Feedback (92700)

The inspectors reviewed previous industry events involving reactivity i management to determine applicability and effectiveness of licensee actions.

8.1 Turkey Point Overdilution Event

) INPO SOER 94-02, Boron Dilution Events in Pressurized Water Reactors, j datt.d September 19, 1994, discussed a similar overdilution event at l Turkey Point and several inadvertent dilution events at other utilities.

4 The SOER made specific recommendations with regard to factors that could potentially affect reactivity as a result of a gradual boron dilution 4 while at power, including: identification and training of those plant i personnel who have the potential to affect reactor coolant system boron-concentration, and conducting a sy;tematic evaluation of their initial

, and continuing training programs to verify that lessons learned from these events are addressed through classroom, simulator, and on-the job i training where appropriate. Further, the SOER recommended reduction in the risk of an inadvertent dilution through administrative controls, availability of appropriate monitoring of key parameters.and/or alarm functions, and minimization of operating crew distractions during activities involving changes to boron concentration.

The inspector reviewed licensee actions with regard to the specific recommendations of the SOER. The licensee had completed numerous actions in the area affecting training, chemistry procedures involving CVCS ion exchanger activity, Health Physics procedures involving decontamination, and Nuclear Materials Management involving Boric Acid purchase and storage. However, the licensee had concluded that operating procedures for boron dilution adequately addressed the recommendations involving administrative controls and availability of appropriate monitoring of key parameters and/or alarm functions. In response to the 50ER, the licensee made no changes to the operating procedures for boron dilution or the related administrative controls.

The inspector concluded that licensee response to the SOER was weak in that it primarily focused on inadvertent dilution events and did not  !

adequately address overdilution events, such as the one described in the 1

i i

! . 17

! SOER that occurred at Turkey Point. The changes in administrative i controls that the licensee made after the January 22, 1996, overdilution event were similar to changes in administrative controls that Turkey l'

Point had made after their overdilution event. This SOER was a missed opportunity to strengthen St. Lucie operating procedures to prevent the

~ January 22, 1996, overdilution event. -

4 8.2 St. Lucie Inadvertent Dilution

! The inspector also reviewed a minor inadvertent dilution event that j occurred at St. Lucie on January 11, 1996, during the valving in of a

. CVCS ion exchanger. During this event, the control room board operator .

i had prematurely diverted, to the VCT, letdown flow through an ion-

' exchanger that had been aligned to the HUT, pending boron sampling by chemistry. As a result, water with a very low boron concentration was added to the VCT. 'This event resulted in a slight increase to Tc that

! was promptly detected and addressed through boration. Licensee corrective actions included a change to procedure OP-0210020, to ensure

i. completion of a boron sample prior to placing ion exchanger in service.

i The inspector noted that the event was not logged in the control room i operator logs; however, the Operations Manager had been made aware of the 4

issue. The inspectors concluded that the licensee had missed another opportunity following the January 11, 1996, inadvertent dilution event to recognize, emphasize, and rectify a weakness in the conduct of operations-during evolutions affecting reactivity.

8.3 Conclusions The inspectors concluded that the licensee's response to SOER 94-02, dated September 1994, which described a similar Turkey Point overdilution event, was werk.. This was a missed opportunity to strengthen operating procedures to prevent the January 22, 1996, overdilution event.

The inspectors also concluded that the St. Lucie inadvertent dilution event of January 11, 1996, was another missed opportunity to strengthen administrative controls for the conduct of operations during evolutions affecting reactivity.

9. Management Expectations (92700)

The inspectors reviewed recent documented indications of management expectations; including a memo from the President - Nuclear Division to plant personnel emphasizing corporate policy on the responsibility and authority of the Nuclear Plant Supervisor and the Shift Technical Advisor

1. on Shift; a memo from the St. Lucie Plant Vice President to plant personnel about procedure usage; various Operations Night Orders; and inter-office correspondence.

18 i 9.1 Conclusions i 'The inspectors concluded that some management expectations had been recently documented and transmitted to plant personnel. Those management

, expectations had specifically addressed adherence to procedures, but had

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not specifically addressed overdilution events or the other issues addressed in this report as apparent violations or weaknesses.

10. Initial Corrective Actions (92700)

The' inspectors reviewed the timeliness and thoroughness of the licensee's l' initial corrective actions for the overdilution event.

j- 10.1 Weakness in Initial Event Investigation 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's initial investigation, as documented in the In- 1 j House Event Report, was timely but was not sufficiently thorough. The

In-House Event Report stated that maximum reactor power was 100.2%,

however, subsequent review by the NRC and licensee found that maximum

. reactor power was approximately.101.18%. Also, the In-House Event Report i did not identify that the reactor operator who had started the boron dilution had left the control room with the dilution in progress and 4 without telling other operators that a dilution was in progress. As a l result of the weakness in the In-House Event Report, licensee management i did.not promptly recognize the significance of the event and the licensee's subsequent more thorough investigation was unduly delayed.

10.2 Corrective Actions i

Following the event, the licensee 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 RO to get prior approval from the 5RO for dilution /boration, 'to require the SRO to 4 directly supervise dilution /boration, to require no RO or SRO turnover during dilution /boration, and to require RTGB walkdown prior to RO or SRO short term relief; and initiated further review of the event.

The inspectors concluded that the licensee's initial corrective actions were reasonably prompt and comprehensive. However, the inspectors noted a weakness in that the revised procedure for manual dilution (after 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.

1

i 19 10.3 Licensee Dissenting Comments 4 The licensee had a dissenting comment on the inspector-identified weakness in the licensee's initial investigation. The dissenting comment, from the Plant General Manager, was:

The initial investigation, for the In-House Event Summary, was done by the STA. . Timeliness was more important than quality at that time. A subsequent more thorough review would be performed by the licensee.

10.4 Conclusions The inspectors concluded that the l'icensee's initial corrective actions were reasonably prompt and comprehensive. However, the licensee's initial investigation was weak. The In-House Event Report significantly understated the peak reactor power during the event and. failed to state that the reactor operator who had started the baron dilution had left the control room with the dilution in progress and without telling other operators that a dilution was in progress. Also, the revised procedure for manual dilution (after the event) did not require the operator at the controls to remain by the dilution controls and to closely monitor the diTution during a manual dilution with no automatic shutoff.

11. Exit Interview The inspection scope and findings were summarized on January 30, 1996, and on February 8, 1996, with those persons indicated in paragraph 1.

The inspectors described the areas inspected and discussed in detail the inspection results listed below. Proprietary information is not contained in this report. There were numerous licensee dissenting comments, as documented in paragraphs 6.3 and 10.3.

hp.g item Number Status Descriotion and Reference EEI 335,389/96-03 Open Operators Failed to folle Procedures for Boron Dilution, Watch Turnover, Procedure Adherence, and Event Reporting (paragraphs 5.1, 5.2, 5.3, and 5.4)

EEI 335,389/96-03-02 Open Inadequate Design Control of Reactor Coolant System Boron Dilution Procedure (paragraph 6.1)

EEI 335,389/96-03 Open Inadequate 10 CFR 50.59 Safety Evaluation of Change to Boron Dilution Procedure (paragraph 6.2)

12. Abbreviations, Acronyms, and Initialisms AEOD Analysis and Evaluation of Operational Data, Office for (NRC)

A0 Auxiliary Operator

20 A0V Air Operated Valve ANPS Assistant Nuclear Plant Supervisor AP Administrative Procedure CEA Control Element Assembly CFR Code of Federal Regulations CVCS Chemical and Volume Control System DDPS. Digital Data Processing System delta P Differentia 1' Pressure DNB Departure from Nucleate Boiling DPR Demonstration Power Reactor (A type of operating license)

EEI Escalated Enforcement Item .

FCV Flow Control Valve FPL' The Florida Power & Light Company FSAR Final Safety Analysis Report gpm gallons per minute HPES Human Performance Evaluation System HUT Hold-up Tank INPO Institute for Nuclear Power Operations IR '[NRC). Inspection Report LCO TS Limiting Condition for Operation '

MWe Megawatts Electric N.A. Not Applicable NPS Nuclear Plant Supervisor NRC Nuclear Regulatory Commission NWE Nuclear Watch Engineer i OP Operating Procedure l

pcm percent milli (a measure of reactivity) l ppm Part(s) per Million l QI Quality Instruction i

RCO Reactor Controls Operator RCP Reactor Coolant Pump RCS Reactor Coolant System Rev Revision RII Region II - Atlanta, Georgia (NRC)

R0 Reactor Operator RTGB Reactor.and Turbine Generator Board SAR Safety Analysis Report SOER Significant Operating Events Report SRO Senior Reactor Operator STA Shift Technical Advisor Tavg Reactor Coolant System Average Temperature TC Temporary Change Tc Reactor Coolant System Cold Leg Temperature '

Th Reactor Coolant System Hot Leg Temperature TS Technical Specification (s)

UFSAR Updated Final Safety Analysis Report Xe Xenon i T

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Pags of 174 i

ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 l COnIDUCT OF OPERATIONS i FIGURE 3

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factors in arriving at the appropriate is not held, the licensee will normally

! severity level will be dependent on the is a matter of public record, such as an be requested to provide a written adjudicatorydecision by the circumstances of the violation. response to en inspection sport,if Department oflabor.In addh with However, if a lican=== mfuses to correct issued. as to the liemanaa's views on the the approval of the Executive Director 1 a minor violation within a reasonable apparent violatione and their root for Operations, conferences will not be 1

time such that it willfully continues, the causes and a description of planned or open to the public where good cause has {

l violation should be catesonzad at least implemented corrective action. been shown alber balancing the beneSt at a Severity LevelIV.

i During the predecisional enforcement of the public observation against the

' D. Violations of Reporting Requirements conferena.the licensee. vendor, or potentialimpact on the agency's other persons will be given an enforcament action in a particular case.

The NRC expects licensees to provide opportunity to provide information complete. accurate, and timely As soon as it is d-'-aaia-d that a consistent with the purpose of the conference willbe opa to public information and reporta. Accordinglya unless otherwise categorized in the conference, including an explanation to observation.the NRt,will the Supplements, the severity level of a theNRCof theimmediateconective Hraa- that the ennfasence be actions (if any) that were taken oPen to public observation as part of the violation involving the failum to make a required report to the NRC will be following identiBeation of the potential agency's trial program. can=h*=n* with based upon the significance of and the violation or nonconformance and the the agency's policy on open meetings, long-term comprehensive actions that " Staff Meetings Open to Public."

circumstances surrounding the matter that should have been reported. were taken or willbe taken to prevent published September 20.1994 (59 FR However, the severity level of an recurrence. l.icensees. vendors. or other 48340), the NRC Intends to announce untimely report. In contrast to no report, persons will be told when a meeting is oPen conferences normally at least to may be reduced depending on the a predecisional enforcement conference, working days in advance of conferences 4

A prsdecisional enforcement through (1) notices posted in the Public

circumstances surrounding the matter.

conference is a meeting between the Document Room. (2) a toll-free A licensee will not normally be cited for NRC and the licensee. Conferences are telephone recording at 800-952-9674

a failure to report a condition or event normally held in the regional offices and (3) a toll-free electronic bulletin unless the licensee was actually aware

, of the condition or event that it failed and are not normally open to public board at 800-952-9676. In addition, the to report. A licensee will, on the other observation. However, a trial program is NRC will also issue a press release and 1 hand. normally be cited for a failure to being conducted to open approximately notify appropriate State Hainan officers

, report a condition or event if the 25 percent of all eligible conferences for that a predecisional enforcement

licensee knew of the information to be public observation. i.e every founh conference has been scheduled and that i reported, but did not recognize that it eligible conference involving one of it is open to public observation.

three categones of licensees ireactor. The public attending open 4

was required to make a report.

hospital. and other materials licenseesi conferences under the trial program may i V. Predecisional Enforcement will be open to the public. Conferences observe but not participate in the Conferences will not normally be open to the public conference. It is noted that the purpose Whenever the NRC has learned of the "f0'C* ment action being conduct o e confomucesunder 3, ,d existence of a potentialviolation for which escalated enforcement action (1) Would b'e taken against an public attendance. but rather to appears to be warranted, or recurnng individual. or if the scuon. though not determine whether providing the public nonconformance on the part of a taken against an individual, turns on with opportunities to be informed of vendor.the NRC may provide an whether an individual has committed NRC activities is compatible with the opportunity for a predecisional wronadoing: NRC's ability to exercise its regulatory enforcement conference with the (2)lavolves significant personnel and safety responsibilities. Therefore, licensee, vendor, or other person before failures where the NRC has requested members of the public will be allowed taking enforcement action. The purpose that the individual (s) involved be access to the NRC regional offices to of the conference is to obtain present at the conference: attend open enforcement conferences in information that will assist the NRC in (3)is based on the findings of an NRC accordance with the " Standard '

determining the appropnals Office ofInvestigations repon: or Operating Procedures For Providing (411nvolves safeguards information. Secunty Support for NRC Hearing And enforcement action, such as:(1) A common understanding of facts, root Privacy Act information, or information Meetings." published November 1.1991 causes and missed opponumises which could be considered proprietary; (56 FR 56251). These procedures in addition. conferences will not provide that visitors may be subject to associated with the apparent violations, normally be open to the public if: personnel screening, that signs banners.

(2) a common understanding of (5) The conference involves medical corrective action taken or planned, and posters. etc. not larger than 18" be misadministrations or overexposures permitted, and that disruptive persons (3) a common understanding of the and the conference cannot be conducted may be removed.

significance ofissues and the need for without disclosing the exposed Members of the public attending open lasting comprehens2ve corrective action. individual's name: or conferences will be reminded that (1)

If the NRC concludes that it has (6) The conference will be conducted the apparent violations discussed at sufficient information to make an by telephone or the conference will be predecisional enforcement conferences informed enforcement decision. a conducted at a relatively small are subject to further review and may be conference will not normally be held licensee's facility. sub}ect to change prior to any resulting miess the licensee requests it. However. Notwithstandmg meeting arv of these enforcement action and (2) the m opportunity for a conference will cnteria, a conference may stillbe open statements of views or expressions of normally be provided before issuing an if the conference involves issues related opinion made by NRC employees at order based on a violatten of the rule on to an ongoing adjudicatory proceeding predecisional enforcement conferences.

Deliberste Misconduct or o c2vil penalty with one or more intervenors or where or the lack thereof, are not intended to to an unlicensed person. if a conference the evidentiary basis for the conference represent final determinations or beliefs.

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j - - FederalRagisemiVol.60, No.126J Friday, June 40,1996-/ Notdes _ _.- 84387~

PeM attendingMaimEferences will to be under on'th. Normally, responses management involvement in ll==aad

, be provided an opi.--.4 to submit underoath willbe required onlyin adivities and a de:rease in protection of l written comments concerning the trial canaadian with Sewrity 14 vel I.11. or the public health and safety. l program anonymously to the regional IH violations or orders.

ofBos. These ===aats will be no NRC uses the Notice of Violation 1. Base CivilPenalty i

subsequently forwarded to the Director as the usual method for formalielag the h NRCim differentlevels of of the Office of Enforcement for review existence of a violation.lasdancn of a g- ieta= for rent severity level 1 and consideration. Natios of Violation is normally the only violations end differentclasses of

} When needed to protect the public enformmaae action taken. except in health and safety orcommon defense uma====. vendors, and other persons. l cases where the criterirfor issuance of Tables 1A and 1B show the benecivil  !

and security, escalated enforcement civil penakles and orders, as set forth in adios, such ta the issuana of an penalties for various reactor, fuel cycle. i

%=diaan VLB and VI.C. respectively, am materials, and vendor . (Civil l l immediately effective order, will be met. However, special cirm=~""

taken before the conference. In these Itiesissued toind vi are  !

regarding the violation findings may i faternuned on a %. case basis.) T cases, a conference may be held after the warrant discretion being exercised such structure of these tables generally takes escalated enforcement action is taken. that the NRC refrains from issuing a

• into account the gravity of the violation VL Enfore===t Actions g",d

• as a primary consideration and the o i *') 8 Yt Pay as a somndary

. This section describes the In ad ition. licensees are not ordinarily was doradon.Generauy, operede enforcement sanctions available to the cited for violations resulting from NRC and specifles the conditions under matters not within their control, such as '" "I 8"* " "" **

t which each may be used.no basic equipment failures that were not inwritwinan Sm8terPotendal i enforcement sanctions are Notices of avoidable by reasonable licensee quality raa miuen ast the publicand licensee Violation, civil penalties, and orders of assurance measures or management OSPl ayees twive higher civil

{ various types. As discussed further in controla. Generally, however. licensees Penah ReganHng tb seconM Section VLD. related administrative are held res '**'" I * 'Y "' *****

actions such as Nouces of 11 ansees to pay the civil penalties. it is emplo[oes.ponsible for the acts of their j Accordingly, this policy Nonconformance. Notices of Deviation. shoul not be construed to excuse not the NRC's intention that the

Confirmatory Action Letters. Letters of personnel errors. economic impact of a civil penalty be so

Reprimand, and Demands br severe that it puts a licensee out of l Information are used to supplement the B. CivilPenalty business (orders, rather than civil enforcement program. In selecting the A civil penalty is a monetary penalty Penalties, are used when the intent is to enforcement sanctions or administrative that may be imposed for violation of(t) suspend or terminate !! censed activities) actions, the NRC will consider consin specified licensing provisions of or adversely affects a licensee's ability enforcement actions taken by other the Atomic Energy Act or to safely conduct licensed activities.

Federal or State regulatory bodies supplementary NRC rules or orders: (2) The deterrent effect of civil penaltios is having concurrent jurisdiction, such as any requirement for which a license best served when the amounts of the in transportation matters. Usually, may be revoked: or (3) reporting Penaltiss take into account a licensee's whenever a violation of NRC requirements under section 206 of the ability to pay. In determining the requirements of more than a minor Energy Reorganization Act. Civil amount of civil penalties for licensees concem is identified, enforcement penalties are desi ned to deter future for whom the tables do not reflect the

action is taken. The nature and extent of violations both b the involved licensee ability to pay or the gravity of the j the enforcement action is intended to as well as by oth r licensees conducting violation. the NRC will consider as reflect the seriousness of the violation similar activities and to emphasize the necessary an increase or decrease on a i Involved. For the vast maiority of need for licensees to identify violations ense-by case basis. Normally, if a i

violations, a Notice of Violation or a and take prompt comprehensive licensee can demonstrate financial Notice of Nonconfor . ance is the normal corrective action. hardship, the NRC will conside,r action. Civil penalties are considered for Payments over time, including mterest.

Severity Level III violations. In addition

• rather than reducing the amount of the A. Notice of Violotm.n c vil penalties will normally be assessed civil penalty. However, where a licensee i A Notice of Violation is a written for Seventy Level I and 11 violations and claims financial hardship, the licensee

notice setting forth one or more knowing and conscious violations of the will normally be required to address violations of a legally binding reporting requirements of section 206 of why it has sufficient resources to safely requirement. no Notice of Violation the Energy Reorganization Act. conduct licensed activities and pay ,

t normally requires the recipient to Civil penalties are used to encourage license and inspection fees. '

! provide a wntten statement desenbing prompt identification and prompt and 2.CivilPenalty Assessment (1) the reasons for the violation or if comprehensive corusction of violations, contested, the basis for disputing the to emphasize compliance in a manner In an effort to (1) emphasize the violation: (2) conective steps that have that deters future violations, and to imponance of adherence to I

been taken and the results achieved: (3) serve to focus licensees' attention on requirements and (2) reinforce prompt

corrective steps that will be taken to violations of significarat regulatory self. identification of problems and root pavent recurrence

and (4) the dato concem. causes and prompt and comprehensive l

when full compliance will be achieved. Although management fnvolvement. correction of violations, the NRC The NRC may waive all or portions of direct or indirect,in a violation may reviews each proposed civil penalty on a written response to the extent relevant lead to an increase in the civil penalty, its own merits and, after considering all

! information has already been provided the lack of management involvement relevant circumstances, may adjust the to the NRC in writing or documented in may not be used to mitigate a civil base civil penalties shown in Table 1A an NRC inspection report.no NRC may penalty. Allowing mitigation in the and IB for Severity LevelI. D. and IU 4

require responses to Notices of Violation latter case could encourage the lack of violations as descnbod below.

t 9 NUREG-1600

Page 9' f 174 ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 CONDUCT OF OPERATIONS FIGURE 3 '

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ENFORCEMENT ACTION WORKSHEET e* e %1 2 ww 4 mMJ c=A A (ST LUCIE OVERDILUTION EVENT] MW* ' -

w /W n:m ,

PREPARED BY: R. Schin DATE: February 5, 1996 N" x1tL6t's

! This Notice has been reviewed by the Branch Chief or Divis.iervDirector and each violation includes the appropriate level of s f t/astohowand when the requirement was violated.

M 1gnature Facility: St. Lucie Unit (s): 1 I Docket Nos: 50-335 i Licensa Nos: DPR-67 Inspection Report No: 50-335,389/96-01 Inspection Dates: January 26-30, 1996 Lead Inspector: R. Schin j 1. Brief Summary of Inspection Findings:

l Concern with operator attentiveness related to a reactivity addition *l l event, and related operator violations of procedures:

a. Operators failed to stop dilution when the proper amount had been added.

b. There was inadequate watch turnover for the operator at the 1 controls during dilution, l

c. Operators failed to follow the Conduct of Operations procedure in performing the dilution procedure (lack of strict / verbatim compliance).

d. Operators failed to adequately report the event to licensee management.

Also, operators exceeded the steady state licensed power limit of 2700 i megawatts thermal (100% power). '

In addition, the licensee nade a change to the procedures as described in the SAR without a 10 CFR 50.59 safety evaluation.  !

i See the attached draft NOV, General Description of Event, Detailed Sequence of Events, Summary of Draft Preliminary Inspection Findings, Control Room Diagram, CVCS Charging System Diagram, Procedures, and FSAR.

PROPOSED ENFORCEMENT ACTION - NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE

i ~

v

'2

2. . Analysis of Root Cause:

Operator inattentiveness to reactivity addition. 3

[ 3. Basis'for Severity Level (Safety Significance):

).

I.C.3 Insttentiveness to duty on the part of licensee personnel, 'while adding reactivity to the reactor, and

) I.C.7 A ~ breakdown in the control of licensed activities involving a e

-number of. violations that are related that collectively represent a significant lack of attention or carelessness toward licensed

( responsibilities. i l

4. Identify Previous Escalated Action Within 2 Years or 2 Inspections?

{

EA 95-180 (EEI 95-16-01); LTOP inoperability due to PORV failure 3_ Event date 8/9/95

5. Identification Credit? No i

. Identified through an event. The licensee initiated an In-House Event

!. Report and gave a copy to the NRC resident inspector promptly after the event. The event occurred at approximately 0220 on January 22, 1996.

1 Missed opportunities:

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

! l strengthen operating procedures to prevent the 1/22/96 i overdilution event.

b. The Unit 2 dilution procedure had been changed in December 1995, 1 but not the Unit 1 procedure, to more accurately describe' dilution tha 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 perforned by strict compliance to the procedure steps; revised the Conduct of Operations procedure to require the RO to get prior approval PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE l

. ~ , , _ _ _ _ . _ . _ . _ _ , __ _ _ _ , , _ _

_ - _. ___ ._._ ._._ _ . _ _ _ _ . _ _ _ _ _ . _ _ _ _. -m .

] - -

3 4

from the SRO for dilution /boration, the SRO to directly supervise l

' dilution /boration, no RO or SRO turnover during dilution /boration, and RTGB walkdown. prior to RO or SR0 short term relief; and initiated

further review of the event.

[ Weaknesses in the licensee's corrective actions included:

i

a. Potential VIO of 10 CFR 50.59: The revised procedure (after the i event) did not support the FSAR Chapter 15 accident analysis assumptions on how dilution was performed. The revised procedure 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 j' lower rate of reactivity addition). The licensee had not performed a safety analysis of this difference and had not revised the procedure and/or FSAR to make them agree.

l 4 '

, b. The revised procedure for manual dilution (after 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.

c. The licensee initial investigation of the event was not thorough

in that it concluded that maximum reactor power was 100.2%.

l Subsequent review by the NRC and licensee found that maximum

! reactor power was approximately 101.18%.

j 7. Candidate For Discretion? (See attached list] Yes - potential

, escalation.

During the last year, the licensee's performance in Operations has declined from SALP 1 to SALP 2 (predecisional). .There have been several

, operator violations of procedures that are, in part, related to the current violation:

1) VIO 335/94-22-02, " Improper Modification of Control Room Logs",

3 November 25, 1994 i 1

i

2) NCV 335/95-07-01, " Failure to Follow Shutdown Cooling Operating y Procedures", April 19, 1995 4

3) VIO 335/95-15-01, " Failure to Follow Procedures and Block MSIS '

Actuation *, October 16, 1995 2

i 4) VIO 335/95-15-02, " Failure to Follow Procedures during RCP Seal  ;

restaging", October 16, 1995 1-

, 5) VIO 335/95-15-03, " Failure to Follow Procedure and Document abnormal valve position in the Valve Switch Deviation Log",

October 16, 1995 l PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE

- WITHOUT THE APPROVAL OF THE DIRECTOR. OE 1 t

4

6) VIO 335/95-15-04, " Failure to Follow Procedures during Alignment of Shutdown Cooling System", October 16, 1995 i 7)- VIO 389/95-18-01, " Failure to Follow Procedures and Maintain Current and Valid Log Entries in the Rack Key Log and Valve Switch

1 Deviation Log", November 27, 1995 i

i

8) VIO 389/95-21-02, " Failure to Follow the Equipment Clearance Order

{

Procedure and Require Independent Verification of a TS Related l Component", December 8, 1995 l l All of the above VIO/NCVs involved licensed operators with a licensee corrective action commitment to strict adherence to procedures. l

8. Is A Predecisional Enforcement Conference Necessary?

Yes Why: There is substantial interest in this event and in the NRC message 4

to the licensee and to the industry. The message for this enforcement

action should be that operators must treat Dilution /Boration as

,i seriously as control rod manipulations. Also, that unusual operations events must be transmitted promptly to management.

If yes, should OE or OGC attend? Yes Should conference be closed? No

9. Non-Routine Issues / Additional Information:

10. This Action is Consistent With the Following Action (or Enforcement j Guidance) Previously Issued: I.C.3 Basis for Inconsistency With Previously Issued Actions (Guidance)  ;

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:

1 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE l

5

16. Exempt from Timeliness: No Basis for Exemption:

Enforcement Coordinator:

DATE:

l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC L ~? CLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

~ -

6 .

ENFORCEMENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION 1

, [] Problems categorized at-Severity Level I or II.

[] Case involves overexposure or release of radiological material in excess ,

of NRC requirements. 4

[] Case involves particularly poor licensee performance.

i [] Case (may) involve wi11 fulness. 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 0! 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.

RE Current violation is directly repetitive of an earlier violation (in part).

[] Excessive duration of a problem resulted in a substantial increase in i

risk. -

t

[] 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 particuiraly good.

[] 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.

l 1

1 PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

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

[x] Applicable licensee procedures or extracts

[] Copy of discrepant licensee documentation referred to in citations such as NCR, inspection record, or test results

[x] Extracts of pertinent FSAR or Updated FSAR sections for citat16ix involving 10 CFR 50.59 or systems operability l

[ ]' Referenced ORDERS or Confirmation of Action Letters

)

l i

[] Current SALP report summary and applicable report sections l

[] Other miscellaneous documents (List):

l l

i PROPOSED ENFORCEMENT ACTION NOT FOR PUBUC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

l 8

l PROPOSE.0 VIOLATION i

'A. Technical Specification (TS) 6.8.1.a required that written procedures be  ;

established, implerwated, and maintained covering the activities  !

recommended in Appendix A of Regulatory Guide 1.33, Rev 2, February i 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 1 operation.  !

+

Operating Procedure No. 1-0250020, Boron Concentration Control - Normal  ;

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 4 during a boron concentration dilution using the direct path to the

] charging pump suction.

i Administrative Procedure No. 0010120, Conduct of Operations, Rev 79, l Appendix D, Crew Relief / Shift Turnover, required that, for short term  :

3 watchstander relief, a turnover be conducted including: general  !

] watchstation status, off-normal conditions, and tests in progress. j i '

Administrative Procedure No. 0010120, Appendix M, Procedural Compliance 4

and' Implementation, required that controlled procedures be implemented l and complied with in accordance with the instructions provided in QI 5-  !

4 PR/PSL-1. Procedure QI 5-PR/PSL-1, Preparation, Revision,- ,

Review / Approval of Procedures, Rev 67,'Section 5.13.2, stated that all  ;

4 procedures shall be strictly adhered to and identified that Operating  !

Procedure'l-0250020 was not considered " skill of the trade" and was not -

to be performed from memory without referring to the procedure,

j Administrative Procedure No. 0010120,' Appendix E, Notification of I

Operations Supervisor /FPL Management, required prompt verbal i notification'of the Operations Supervisor for unplanned reactivity  ;

changes.

f

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 i 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

{ . . . _ . _

9 concentration dilution was in progress. As a result, the relief -!

operator at the controls was unaware that a boron concentration i dilution was-in progress and failed to adequately monitor and.

control-the dilution.

y i

3. On January 22, 1996, at apprcximately 2:30 a.m., operators

^

performed Operating Procedure 1-0250020 from memory, witnout 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 been 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 reactiv.ity changes that had occurred.

G. 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 reactor 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.  !

2 Contrary to the above, on. January 22, 1996, between approximately 2:20 and 3:30 a.m., the reactor core thermal pcwer 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 minutes and a. peak reactor power of approximately 101.18% was reached.

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 the 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 bas'is for the  !

determination that the change does not involve an unreviewed safety  !

question. l i

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- i 96-017 to procedure 1-0250020, Boron Concentration Control - Normal.  ;

Operation, Rev.~35, added instructions for dilution in manual and ,

directly to the suction of the charging pumps. However, the SAR, '

paragraph 15.2.4.1, states that boron dilution is conducted under strict  ;

administrative procedures which limit the rate and magnitude of any j required change in boron concentration. Further, the SAR states that boron dilution must be conducted in automatic (such that w'ren the  !

PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE l

10 <

specific amount has been injected, the demineralized water control valve is shut automatically) and describes introduction into the volume

, control tank (VCT). The SAR concludes f. hat, in part, because of the procedures involved, the probability-of a sustained or erroneous

- l dilution is very low. The licensee %plemented Temporary Change 1 l 017 on January 23, 1996, without a written safety evaluation.

1 General Descriotion of the Event At.approximately 0225 on January 22, 1996, the Unit I control board Reactor j Controls Operator (RCO) began a manua) dilution to the RCS by aligning primary makeup water (demineralized water) directly to the suction of the IB Charging 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.

He requested that the desk RCO relieve him so that he could prepare his lunch.

.During the turnover, there was no discussion of the dilution in progress.

Following the turnover, the relief operator at the controls and the Nuclear dilution was in progre)ss.The Plant Supervisor original (NPS board RCO ,- who returned was 5-10 between at the desk RCO st minutes later and immediately recognized his error. He informed the other RCO  ;

of the overdilution, which was overheard by the NPS, and stopped the dilution.

1

' The NPS directed the ANPS take charge and begin a manual boration. Unit I  ;

entered 2-hour TS LC0 Action Statement 3.2.5 for T, greater than 549*F. The l 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 T, was not exceeded. and the guidance of the Jordan memorandum on maximum )

reactor power was not exceeded. The operators did not verbally notify plant  !

management or the NRC of this event. I Detailed Seouence of Events (Note that the times for the sequence of events are approximate and only relevant events are mentioned) 1/21/96 11:00 p.m. Incoming mid shift assumed Unit I responsibility with the Unit at 100% power, 870 MWe, Tavg at 575 degrees F, That 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.m. Board RCO reset to zero the primary water (to VCT or charging  !

pump) flow' totalizer in preparation for inventory balance (RCS i PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

11 i

- leak rate calculation) l i  !

11:00 p.m.-

'2:00.a.m The board RCO recalled performing at least two dilutions of l l

' approximately 35 gallons each between 11:00 p.m. and 2:20 a.m.  !

without resetting the totalizer. .

1/22/96 '

i 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 j , also present near NPS l

+

1 xx:xx a.m. ANPS turned over control room senior reactor operator i  !

responsibility to NPS and proceeded to the kitchen to prepare [

breakfast t t

xx:xx a.m. Desk RCO left control room to go.to the kitchen  !

i 2:20 a.m. Normal continued fuel burnup resulted in indicated Tc of 548.7 t 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 RCO 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 1[ and A0V-2525. The flow rate 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. i 2:27 a.m. After acknowledging the annunciator, the board operator decided to .I proceed to the kitchen to prepare his meal. The board operator t 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.

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

+w ee l

12 400 gallons was added.

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 l hour action statement associated with Tect.nical Specification '

3.2.5, DNB paramenters was recognized and later logged.

2:36 a.m. The desk operator directed the board operator to iritiate 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% I 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. l 5:45 a.m.-

6:00 a.m. Shift turnover occurred. It appears that the dilution event was '

not discussed with the oncoming shift. l 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 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.

7:45 a.m. Senior Plant management was notified of the event during the morning meeting.

10:00 a.m. NRC resident inspector was given the event report that was initiated associated with the event.

I PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE

%flTHOUT THE APPROVAL OF THE DIRECTOR. OE

13 ST. LUCIE ONSITE EVENT. FOLLOWUP INSPECTION  !

OVERDILUTION EVENT of 1/22/96 l (Exit was at 10:00 a.m. on 1/30/96) .

Inspectors:

R. Schin, S. Sandin, B. Desai '

i d

Summary of draft oreliminary findinas:

1. Magnitude of power and temperature excursion

, a.. Reactor power ,

Peak reactor power was approximately 101.18% }

l -

100%' power was exceeded for approximately 70 minutes  :

101% power was exceeded for approximately 4 minutes -

The event was within the accident analysis 1

The guidelines of the Jordan memo were not exceeded i

b. Cold leg temperature 4

Peak Tc was approximately 549.9 degrees F  ;

TS limit of 549 was exceeded for approximately 50 minutes  ;

TS ?-hr. action statement was properly entered and was not exceeded 3

2. Concern with operator attentiveness - Potential / Apparent VIO of procedures (Enforcement panel form completed on this issue):

a. Operators failed to stop dilution when the proper amount had been added, i b. There was inadequate watch turnover for the operator at the controls during dilution.

2 c. Operators failed to follow the Conduct of Operations procedure in performing the dilution procedure.

i d. Operators failed to adequately report the event to licensee management.

f 3. Concern with control room command and control - Weakness

! a. The SRO in the control room was not aware of the dilution in

] progress.

b. The board operator did not inform the SRO of dilution - this was a general practice at the site and not required by procedures.

2 c. The watchstander board was not maintained (on Saturday).

4 d. The SR0 in the control room was allowed to be in the ANPS office i 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).

4

PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE a

l

4. Weaknesses in procedures

a. The Unit 2 dilution procedure had been changed, but not the Unit 1 l procedure, to more accurately describe dilution the way the operators had performed it for years (in manual and direct to the l

charging pumps). During the event, manual dilution could not be accomplished.by using the Unit 1 procedure in compliance with the Conduct of Operations.

I

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 j dilution with no automatic shutoff. -

5. Weaknesses in corrective action ,

l

a. Potential VIO of 10 CFR 50.59: Revised procedure (after the i event) did not support the FSAR Chapter 15 accident analysis assumptions on how dilution was performed. The FSAR assumed ,

dilution in automatic and to the VCT. i

b. l The revised procedure for manual dilution (after 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,

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

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 APPROVAL OF THE DIRECTOR. OE

n

. b. Operators routinely did not log reactivity additions; however, the licensee's conduct of Operations procedure stated that operators i

'should log reactivity changes. j l

LICENSEE DISSENTING ComENTS " '

i

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 l Weinkam), included: y

a. The previous procedure allowed diluting in manual and directly to j the suction of the charging pumps, and that had been the practice.

for many years. Therefore, the temporary change on 1/23/96 (after i the event) did not change the method of dilution, but only i clarified a previously existing procedure and made it conform to

" verbatim compliance" rules. The inspectors did not disagree. In i

fact, further. review, as requested by the inspectors, found that j the first time the dilution procedure was changed to allow opening i 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 l' 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. -

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 '

the flowrate of this event and therefore that analysis bounds this event. )

The inspectors did not disagree,

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 i suction of the charging pumps was made before the operating j 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 directly to the suction of the charging pumps, that method was PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

ifi 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 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

,. 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:

a. The initial investigation, for the In-House Event Summary, was

done by the STA. Timeliness was more important than quality at that time. Subsequent more thorough review would be performed by the licensee. The inspectors acknowledged the licensee's comment, 4

e I

4 PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

.f j . . . . . .

Proposed Operator 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 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 tem 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 at.cordance with the instructions provided in QI 5-PR/PSL-1, Preparation, Revision, Review / Approval of Procedures, Rev 67.

Procedure QI 5-PR/PSL-1 Cection 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 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 SRO 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 he failed to include general watchstation status and conditions including that a boron concentration dilution was in progress. As a result, the relief operator at the controls was unaware that a boron concentration dilution was in progress and failed to adequately monitor and control the dilution.

3. On January 22, 1996, at approximately 2:30 a.m., the Unit 1 operator 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 dilution that was performed could not have been performed by strictly adhering to the procedure.

These violations represent a Severity Level III problem (Supplement ).

Pursuant to the provisions of 10 CFR 2.201, ************* 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 facility that is the subject of this Notice, 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 a 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. Your response may reference or include previous docketed correspondence, if the correspondence adequately addresses the required response. If an adequate reply is not received within the time ,

l specified in this Notice, an order or a 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.  !

Under the authority of Section 182 of the Act, 42 U.S.C. 2232, this response shall be submitted under ' oath or affirmation. I Because your response will be placed in the NRC Public Document Room (PDR), to l the extent possible, it should not include any personal privacy, proprietary, or safeguards information so that it can be placed in the PDR without 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 withholding the information from the public.

Dated at Atlanta, Georgia this day of Februay 1996 '

Page 1 of20. ..._ .-..

FLORIDA POWER & LIGHT COMPANY ST. LUCIE UNIT 1 -

OPERATING PROCEDURE NO. 1-0250020 j, ,p x- ,

(

REVISION 35 xI -

1.0 TITLE

BORON CONCENTRATION CONTROL - NORMAL OPERATION rnec : udenotisiidon]

2.0 REVIEW AND APPROVAL:

Reviewed by Plant Nuclear Safety Committee _

Approved by 5/3019A K.N. Harris Plant General Manager 6/31974 Revision 35 Reviewed by Facility Review Group 8/10 & 8/17 1995 Approved by_ C. L. Burton 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 (RWT) at a desired baron concentration and provides instructions for the following modes of control:

3.1 BORATE 3.2 DILUTE 3.3 MANUAL 3,4 AUTOMATIC 3.5 Shutdown Cooling (SDC) Baron Concentration Controt S1 OPS DATE DOCT PAOCEDURE DOCN '-0250020 SYS COMP COMPLETED ITM 35

Page 14 of 20" .

ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-0250020. REVISION 35 ..M

^

SORON CONCENTRATION CONTROL - NORMAL OPERATION

8.0 INSTRUCTIONS

(continued) 8.4 (continued) 1 i j

3. 9:.

Enter the number of gallons to be added into the PMW Batch integrato and set desired flow rate on FRC-2210X (Makeup Water Flow). " )

4.

Start one Primary Water Pump if not running.  !

5. Place V2512 in the OPEN position.

i

6. a Place Mode Selector switch in DILUTE and observe flow indication of FRC-2210X.

7.

Monitor VCT level to ensure tank ooes not fill up to high level alarm. For l extenoeo dilutions, match makeuo flow with charging flow using the PMW '

makeup flow controller to prevent over-filling the VCT while diverting letdown.

8.

Upon completion of dilution, return V2512 control switch to AUTO or CLOSED position.

9.

Return Mode Selector Switch to AUTO or MANUAL.

10. Ensure that the desired reactivity change occurs.

1 8.5 Manual Mode of Operation 1.

Determine the desired volume to be aeded to the VCT and calculate the  !

proper blend ratio using the most recent chemistry boron samples of the l' i 1 A or 1B BAMT and the RCS If the chemistry samole for the RCS is not available then use the boronometer reading. {

P ge .15 bf 20- ~-

ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-0250020 REVISION 35

h BORON CONCENTRATION CONTROL - NOPMAL OPERATION-

8.0 INSTRUCTIONS

(continued) 8.5 (continued)  :

O ,

..; l NOTE zg i The following formulas can be used to determine volume and blend ratio.

p Remember to make note of the current totalizer readings. 4-Volume to be added := desired VCT level % - actual VCT level % X 33.8 gal/f Blend ratio = BAMT Concentration divided by RCS Concentration minus one  ?)

BAMT - 1  ;

RCS '

2.

Ensure Mode Select switch is selected to MANUAL.

3.

Place FRC-221DY and FRC-2210X to manual and close FCV-221 FCV-2210X bytaking the controller output to zero.

,I 4.

Ensure 1 A or 1B primary water pump is running.

5.

Ensure the BAM pump recire valves V2510 and V2511 are open.

6. Start either the ) A or 1B BAM pumo.

7. Ooen the Bone Acid Makeup isolation valve FCV-2161.

6 8.

Ensure FCV-2210X, Reactor Makeup valve, selector switch is in AUTO. t

9. Ensure FCV-2210Y, Boric Acid valve, selector is in AUTO.

j 10.

If blending directly to the VCT, then open V2512, Reactor Makeup Water stop valve.

i

11. '

If direct path tothe charging pump suction is desired, then open valve V2525, Boron Load Control Valve.

M

1 P:ge 16 ef 20- ..

ST. LUCIE UNIT 1 E OPERATING PROCEDURE NO. 1-0250020. REVISION 35 SORON CONCENTRATiCN CCNTROL -i40RMAL OPE:.ATICN i 8.0 INSTRUCTIONS _: (continued) 8.5 (continued) l CAUTION s fI

. To preclude lifting the VCT relief valve while using V2525, do not allow the" l

4 combined PMW anc boric acid flowrates to exceed the running charging pump (s) capacity.

' , 'I

.t, 'l

12.

Adjust FRC 2210X and FRC-2210Y to the desired flow rates.

NOTE Monitor VCT level for increase. ,

1

NOTE

, The addition of Boric Acid should be completed before the PMW, such that.

c the total blend volume remaining allows for at least 30 gallons of pnmary makeup boric acid. water alone, to flow through the lines and flush out any remaining j 13. I When the desired amount of Boric Acid has been added, piace the 4

selector switch for FCV-2210Y to CLOSE. j

>l

14. j ,i When the Boric Acid and water flow totalizers show that the proper

amounts have been acded to the VCT then close V2512 or V2525, which ever was used. >

h 15.

Place the running BAM pump switch to AUTO and ensure pump stops. I i

1

16. Close FCV-2161. i i

{

17. Close FCV-2210X. ~

i I

i

18. '

!- Monitor for any abnormal change in temperature. Check Boronometer for l undesirable change in Baron Concentration.

i k

l 4

1 e

e

QI 5-PR/PSLh1_: - . . . , _

y. .. -

December,1995 Page 92 of 101 FIGURE 4 TEMPORARY CHANGE REQUEST (Page 1 of 3)

A' Refa.,s Wormatem (Originator to complete)

St. t.ucie Unit # PSL i Tc a l ~% ~ of 7 Proc,:sture

Title:

'13oeos Cow etrerArma dwr#.g -vaeme 6t3wn,,J Proced'Jre Number: oP f-taa m.30 J O Rev. 3 *i"

• Reascn for change: A00 PlZeufar. GwoducE tB2 CW.s owa rw , mA Art.uru Am &wn u JF The h2r . s'Tus iWMwarn na is tw Ykr nr w..,er u o f a - a M tu.a a c , u v a s.

Originator: E %NenA Phone: KDG Date:JAn/ 23 /1994 B Proceeurat Camvis (Originator to complete)

Yes N O is the intent of the procedure aftereo? (Tech. Spec. 6.8.3.A) If yes, a TC is .N,1T, applicable. A PCR is required.

O is this Temporary Change for a one-time use? If yes, this TC can be executed gg.

[ 1g3.only.

. If no, this TC may be used up to 90 day submit a procedure change request incorporating this TC at the same time the TC is approved.

Department Head or Designeel _ a A C.1 W I M__./N O

O

[ designee who is jurisdictionally responsible for the Q.l. sh i

Quality Manager or Designee / / l t

Decanment Head or Designee /

___/

C Temoorsrv Chance contents: (originator to compteter Does this Change:

Yes No O g incorporate complex or extensive changes? If Yes. Subcommrttee required.

Subcommrttee initials O [ Modify instrument setpoints?

O  % Delete an independent venfication?

O [ Alter a QC holdpoint?

O y Modify a procedural step which alters a regutatory reautrement as identified in the proceeure? l O g Alter the first execution of a procedure? (Preop, LO!)

O g Addition of any chemicals?

NOTE If any of the above entena are marked yes. pner FRG review is requireo.

/R6:

~~

Ql'5-PR/PSL-1

~

Revision 67-December,1995 Page 93 of 101 i

FIGURE 4 j TEMPORARY CHANGE REQUEST '

(Page 2 of 3)

Tc # .f.-%

D at 7 10 C#gt 50.58 L- ,

i Yes No 1.

Does me thenge represent a snenge e me landly se deemmed in the SAR7 2.

Does me change represent a enenge a pmcoeures as assenbod in me SAR7 3.

la me enange ansonised vne a test er ascenmora not demonbod in me SAR7 l

4 Coubs me enange anoot numeer seloly n a way not pronousy ensumed in the SAR7

[

(7

$. A.

Does the change remare a cnenge m the Techmcad am?

M If the answer to M the above 10 CFR 50.59 screening questions are no (Questo 1

• 5) then a safety evalylation,is naweoutred.

E STArewswsegrensei.

MT//4 Di  %

Date /M3'N Does ma mange (NPS to conumewf j Yes No 1.

Comovemme me ascenson of trans of equemert?

2. Potencedy isoisse preense

3. Defeat summens egness? I 4, '

Deiset annenerenet or ensamcmiirnestacas?

, 5. i I Aher me comgeston of an evteunen aue to an operser wonc arowns.

I If yee m No. 5. aumonzason tem me Ment Generes Manager or site Vice Preecent oned be cotoned l

One '- /

Yes No C Prior FRG recew recnated?

If any of thNLbove e M Ongtnator. M [ l ntena h are manced yes, ciscuss possible attematives w:th the NPS Signesure M \ M>

Date I / '

F FnG n::-. J Mont Genenu Manager Appnwal Date / '

FRG Nwneer -

TNe cnonge ened be rewowee (rf pnar FRG aewsw a not recured) by tne Feauty Rowow Group ano approves try the Rent Generes Manager eaNin 14 days of the aumonzason osta. (Tech. Spec. 6.8.3.C)

REJECTED by FRG/ Rara General Manager _

Date / '

Reason.

Retan to Ortgmmer 11is the rosconsibuny of tne ongmenor of the retecten temporary enange to cances the enange an the Room, costroy ad Aoks cocess and hatt al sucecouerW evoeunone uomg Ins temporary enange.

- ~ ~ - - -

Rension 67' j December,1995 Page 94 of 101 RGURE 4 l l TEMPORARY CHANGE REQUEST (Page 3 of 3)

l

1. 't G TC e t % gr1 i

i Aowaf: (This change shall have pnor app l managenunt staff.) (Tech. Spec. 6.s.as) n ff #8 m a mer of the piant hgenwnt set gig kqf Ihp NPS Signature d Dah _ l /_ Uf 3 b

'N H v -E " U* '

carcellation Authonzanon (NPS/ANPS) Date /f Reason:

1

• l l .

2 .

I i

i  !

_ Page 14-o_f ..

ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-0250020, REVISION 35

. ' " .f ..

BORON CONCENTRATION CONTROL - NORMAL OPERATION - -.cW. '

i-

8.0 INSTRUCTIONS

(continued)

$2 8.4 (continued) 3.

Enter the number of gallons to be added into the PMW Batch Integ and set desired flow rate on FRC-2210X (Makeup Water Flow).

4. Start one Primary Water Pump if not running.

5. Place V2512 in the OPEN position.

6.

Place Mode Selector switch in DILUTE and observe flow indication of FRC-2210X.

7.

Monitor VCT level to ensure tank does not fill up to high level alarm. For extended dilutions, m'atch makeup flow with charging flow using the PMW makeup flow controller to prevent over-filling the VCT while diverting letdown.

8. Upon completion of dilution, retum V2512 control switch to AUTO or CLOSED position. '

i 9.

Retum Mode Selector Switch to AUTO or MANUAL

10. Ensure that the desired reactivity change occurs. '

N 3 8.5 Manual Mode of Operation

\

1. wJ BlJ i

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 'l A or 1B BAMT and the RCS. If the chemistry sample for the RCS is not available then use the boronometer reading. -

l

~

. EM_15 of.20 i

ST. LUCiE UNIT 1 OPERATING PROCEDURE NO. 1-0250020, REVISION 35

.2 .

BORON CONCENTRATION CONTROL - NORMAL OPERATION .% ,

8.0 INSTRUCTIONS

(continued)

' . 8.i.5 8.5 (continued) v.c i i

Ei

$5  !

.N.QTg.

The following formulas can be used to detemtine volume and blendH$

! ratio.

e Remember to make note of the current totalizar readings. i l Volume to be added = desired VCT level % - actual VCT level % X 3j  ;

Blend ratio = BAMT Concentration divided by RCS Concentration minus one)

BAMT-1 l

} RCS  :

j y E g Ensure' Mode Select switch is selected to MANUAL

i. ,

C. $ FCV-2210X Place FRC-2210Y and FRC 2210X to manual and c by taking the controller output to zero.

D- @ Ensure 1 A or 1B primary water pump is running.

j E-@ Ensure the BAM pump recire valves V2510 and V2511 are

) N '

R@ Start either the 1 A or 1B BAM pump.

% Open the Boric Acid Makeup isolation valve FCV-2161.

4 $* N. @ Ensure FCV-2210X, Reactor Makeup valve, selector switch is I

I,

y C-@ Ensure FCV-2210Y, Boric Acid valve, selector is in AUTO .

i 2

l "*@ if blending directly to the VCT,' then open V2512, Reactor Makeup Water mop vWve.

}) g l

h if direct path to the charging pump suction is desired, then open v 1

• V2525, Boron Load Control Valve.

A hs' T.a2 8N3 y i

2 N N l

I

, ~

Pcge 16K20 -

i ST. LUCIE UNIT 1 .hc OPERATING PROCEDURE NO. 1-0250020, REVISION 35 I.

BORON CONCENTRATION CONTROL - NORMAL OPERATION o

8.0 INSTRUCTIONS

-(continued)

,,[,

is 8.5 (continued) h, .

ims CAUTION To preclude lifting the VCT relief valve while using V2525, do not allow the Mi!

combined PMW and boric acid flowrates to exceed the running charging g pump (s) capacity.

l t k

9

% Adjust FRC-2210X and FRC-2210Y to the desired flow. rates.

\,

i I

Is Y Monitor VCT level for increase.

1 l

NQTE 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 primary makeup water alone, to flow through the lines and flush out any remaining boric acid.

M- @ When the desired amount of Boric Acid has been add @ ac selector switch for FCV-2210Y to CLOSE.

N <@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 5Dp.A u a Wu~e ad O'[VPlace the runriing BAM pump switch to AUTO. 1 P. O Close FCV-2161.

'D s G.8. Close FCV-2210X. I E $ Monitor for any abnormal change in temperature. Check Boronometer for undesirable change in Boron Concentration.

M AW MM b E 1 8,[. 3 NAJ l

l

i ST. LUCIE UNIT 1 i P OPERATING PROCEDURE NO. 1-0250020, REVISION 35 BORON CONCENTRATION CONTROL - NORMAL OPERATION j

8.0 INSTRUCTIONS

(continued)

I 8.5 (continued)

. 2. Manual Dilution

^

SQ.TE 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.

M C.

h Ensure that FRC-2210X, Make-up Water Flow, is in MANUAL and reduce the controller output to zero (0).

D. Ensure that FRC-2210Y, Boric Acid Flow, is in MANUAL.

O and reduce the controller output to zero (0).

E. Ensure that FCV-2210Y, Boric Acid Valve, selector is in CLOSE.

j jg F. Ensure that either the 1 A or the 1B Primary Make-up Water Pump is running.

G. Place FCV-2210X, Reactor Make-up, selector switch in AUTO. '

H. H diluting to the VCT, ]han OPEN V2512 Reactor Make-up Water Stop Viv.

l. M diluting directly to the suction of the charging pumps,

]han OPEN V2525, Boron Load Control Valve.

I

, . . . - -- l ST. LUCIE UNIT 1-OPERATING PROCEDURE NO. 1-0250020, REVISION 35 BORON CONCENTRATION CONTROL - NORMAL OPERATIO t

8.0 INSTRUCTIONS

(continued) ,

8.5 (contithed)

2. Icontinued) 8 q CAUTION -

To preclude lifting the VCT relief valve while using V2525, do NOT allow the PMW flowrate to exceed the running charging pump flow rate.

.1.,

Adjust FRC-2210X to the desired flowrate.

l C;

11 necessary to maintain the desired VCT level, Then L

h divert the letdown flow to the WMS by placing V2500, VCT Divert Valve, in the WMS position. '

l L

i i

\D When the desired VCTlevelis reached Ihan- t

@I 1.

i Return V2500, VCT Divert Valve, to the AUTO  !

position.

M  !

g '

2.

Ensure that V2500 indicates CLOSED.

\

I Q E.

When the desired amount of PMW has been added,Ihen n place the FCV-2210X selector switch in the CLOSE position.

NL "

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.

2. Undesired change in the RCS baron concentration by boronmeter indication.

s

~.

f l -

ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-0250020, REVISION 35 BORON CONCENTRATION CONTROL - NORMAL OPERATION'

8.0 INSTRUCTIONS

(continued) l l 8.5 (continued) i

3. Manuai Boration f

EQ.la 4' VCT level equates to 33.8 gallons per percent of scale on LIC-2226, VCT Level.

I 2

A.

Determine the desired volume of boric acid to be added.

M B.

Ensure the Make-up Mode Selector switch is selected to D MANUAL. ,

C. Ensure that FRC-2210X, Make-up Water Flow, is in g MANUAL and reduce the controller output to zero (0).

Os g D. Ensure that FRC-2210Y, Boric Acid Flow, is in MANUAL <

and reduce the controller output to zero (0).

N  !

E. Ensure that FCV-2210Y, Boric Acid Valve, selector is in CLOSE.

() , F.

Ensure that either the 1 A or the 18 Primary Make-up N, j Water Pump is running.

ECLTE 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 1B BAM Pump.

H. Place FCV-2210Y, Boric Acid Valve, selector switch in AUTO.

i 1.

, OPEN FCV-2161, Boric Acla Make-up lselation.

J. 11 borating directly to the VCT, Iban OPEN V2512, Reactor Make-up Water Stop Viv.

. ; ._  : n r__

4 .

a ST. LUCIE UNIT 1 OPERATING PROCEDURE NO. 1-0250020, REVISION 35 BORON CONCENTRATION CONTROL - NORMAL OPERATION

8.0 INSTRUCTIONS

(continued) 8.5 (continued)

3. (continued) i K. E borating directly to the suction of the charging pumps, Ihan OPEN V2525, Baron Load Control Valve.

L Adjust FRC 2210Y to the desired flowrate.

9 M. H necessary to maintain the desired VCT level,Iban g divert the letdown flow to the WMS by placing V2500, j VCT Divert Valve, in the WMS position.  !

n I

N. WhAn the desired VCT level is reached, ]han L

1. Return V2500, VCT Divert Valve, to the AUTO  !

D. position. l Y 2. Ensure that V2500 indicates CLOSED.

jQ , O. Whan the desired amount of boric acid has been added, tx  ; Blan place the FCV-2210Y selector switch in the CLOSE l, position.

i i P.

' CLOSE FCV-2161, Boric Acid Make-up Isolation.

I t CAUTION I

! To preclude lifting the VCT relief valve while using V2525, do NOT allow l the PMW flowrate to exceed the running charging pump flow rate. '

I

! Q. STOP the running BAM pump and place the selector

} switch in the AUTO position.

I l

• l j

l l

{ ST. LUCIE UNIT 1 j OPERATING PROCEDURE NO. 1-0250020, REVISION 35 ,

l 2

BORON CONCENTRATION CONTROL - NORMAL OPERATION

8.0 INSTRUCTIONS

i (continued) 8.5 (continued)

J i

3. (continued) i i

i R.

11 flushing the CVCS piping following boration is desired, 4 Ihta:

1 4 1. Place FRC-2210X, Make-up Water Flow, controller q in AUTO.

h CAUTION

' g To preclude lifting the VCT ralief valve while using V2525, do NOT allow the PMW flowrate to exceed tha running charging pump flow rate.

G 2. Adjust FRC-2210X to the desired flowrate to flush I k the lines with a total of at least 30 gallons of PMW.

1

N'

3. W.han the desired amount of PMW has been k4:. added,Ihan place the FCV-2210X selector switch in the CLOSE position.

4.

N '

Place FRC-2210X in MANUAL and reduce the controller output to zero (0).

S. CLOSE V2512 or V2525, whichever was used.

T. Ensure that FRC-2210Y, Boric Acid Flow, is in MANUAL and reduce the controller output to zero (0).

,. U. Monitor for unexpected results:

1. Abnormal change in the RCS temperature.

, 2. Undesired change in the RCS boron concentration by boronmeter indication.

_ . . _ . .QL5-PR/RSG.1Z - - ~ ~., ~ .

Revision 67~

December,1995 Page 1 of 101 i

Pst I O n FLORIDA POWER & LIGHT COMPANY J. \ \

o i

NUCLEAR ENERGY DEPARTMENT L I 5 ST. LUCIE PLANT '

4 Mt0CF. DURE PRobuCTION 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 l

2/31975

! Revision 67 Revieweo by FRG 12/819_S.E_

Approved by J. Scarola

[ Plant General Manager 12/819_9,E_

2.0 PURPOSE

2.1 This procedure provides adrninistrative guidance for the preparation, review, approval and revision of all plant procedures and letters of instruction, for use at the St. Lucie Plant.

f 41

• 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).

i 4

1 S ,,,,,,, OPS DATE DOCT PROCEDURE DOCN 01-5 1 SYS COMP COMPLETED ITM 67

) .-

~

~'

i_ ~QI.5-PR/Psts .1

~ ~ ~ ~ ~

Revision 67' December,1995 Page 41 of 101

5.0 INSTRUCTIONS

(continued)

{

5.12 (continued)  !

i 2.

Controlled vendor technical manuals may be utilized as references to safety or non-safety related NPWOs to provide technical guidance (e.g., !

DWGs, specifications, torque values, dimensional information, voltage / current values, etc.) to supplement an invoked plant approved i

procedure / guideline or the work scope / instructions without prior FRG  !

Review / Plant General Manager approval. In this case, the vendor'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 016-PR/PSL-1.

5.

The maintenance and preventive maintenance requirements specified in technical manuals shall be considered when writing maintenance -

procedures. Vendor recommendations for preventive maintenance activities or frequencies contained in these Vendor Tech. Manuals may be deviated from, provided a technical review is performed by the respective maintenance engineenng group. 1

6.  !

Distribution of revisions to vendor technical manuals shall be maintain by the information Services Supervisor or designee.

5.13 Adherence to Procedures:

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 this 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.

B. ,

Procedures and instructions that are of a technical nature shall be followed sequentially except as specifically cllowed by approved plant procedures.

-. _ . 2 .. a ... . . . .

. .. _ . . . .c ._._Qt 5-PR/PSL=1. _ ___. _ ._~_-~

Revision'6T December,1995 Pr.gs 42 of W1

5.0 INSTRUCTIONS

(continued) 5.13 (continued)

2. (continued)

B. (continued) 1.

Required sign-offs and data entries shall be made as each step is performed.

2. If a procedure step cannot be completed as wntten, or if in the judgement of the individual performing a procedure, completion 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 stopped the systenvcomponents placed in a . safe condition and the Nuclear Plant Supervisor shall be notified.

3. Deviation from Procedure Valve Checklists may be made provided the deviation is noted in ink on the applicable valve alignment and is approved (initialed and dated) by the Nuclear Plant Supervisor.

3. Personnel shall not give directions, guidance, recommendation, or j

clarifications which conflict with approved procedures.

4. Adherence to procedures shall be accomplished by use of one of the following methods: ,

A. Method 1 - Procedure Present Durino Pedormance of Activity: The types of procedures that shall be present and referred to directly are:

1.

Those procedures developed for extensive or complex jobs where reliance on memory cannot be trusted.

2. Tasks which are infrequently performed.

3. Tasks which must be performed in a specified sequence and/or

- which verification is documented by initia! cr signature.

4

. _ _ . . _ . _ . . ~ ~ ~ ~

..iOL5-PR/RSG.1 -~

i Revision 67

December,1995 Page 43 of 101

}

5.0 INSTRUCTIONS

(continued) j E.13 (continued) 3 B.

Method 2 - Memorization: Method by which the procedural steps for the required actions are committed to memory. This method does not permit any deviation from the Procedural Adherence Policy.

1.

i' Procedures for which actions should be committed to memory are immediate Actions in Emergency Operating Procedures and Off j Normal Operating Procedures.

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 -

l activity. However, copies of procedures shall be available to the user at his/her work location for reference during performance of l the task, if necessary.

5.

Procedural adherence may be accomplished by use of a Temporary I l Change, if necessary.

6. When used in a procedure the word "shall" is used to denote a requirement, the word "should" to denote a recommendation and the word "may" to denote permission, neither a requirement nor a recommendation.

7. Independent Verification:

A. Independent Verification has been defined in ADM-17.06,

" Independent Verification." Definitions of Independent Verification should not be added to procedures as they may conflict with the guidance outlined in ADM-17.06.

l l

I 4

i ~

PageioL174.

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120 _

REVISION 79 1

PSt._9

.1.0 E: sm c r. g E (I 3 CONDUCT OF OPERATIONS Ok- og

, PROCEDURE -

2.0 REVIEW AND APPROVAL: -

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 19.91

Approved by J. Scarola Plant General Manager 12/21 1995 2

3.0 SCOPE

j 3.1

Purpose:

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 l

regulatory requirements.

This procedure applies to all persons in the Operations Department. It identifies operational requirements and management policies necessary to ensure the daily conduct of plant operations is consistent with good operational and engineering practices.

I S_ OPS DATE j DOCTlROCEDURE i 0010120 DOCN SYS l COMP COMPLETED ITM 79

~ ~ ~ ~

Phge.41.of_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.

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 ~ l than 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />si. then the following instructions provide the minimum requirements for shift relief: l

a. General watchstation status,

b. Off-normal conditions.  !

c. Tests in progress.

2. The applicable unit ANPS shall be notified immediately after the shift I tumover nas been completed.

3. If an individual is expected to be aosent for period of greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, j then an Individual Relief / Split-Shift Tumover shall be performed, i

i _. _ -- ~

t

-Page.42'of 174" ~

ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 79 CONDUCT OF OPERATIONS APPENDIX E '

NOTIFICATION OF OPERA 110NS SUPERVISOR /FPL MANAGEMENT (Page 1 of 3) 1.

The Nuclear Plant Supervisor is respansible for notifying higher station authonties i and appropriate station personnel. Aov4: ice notification should be made when i possible. ' The following situations require prompt. verbal _ notifications: - -

~

Notify the Operations Supervisor for the following situations: . '

1 A. Any event that would cause entry into an Emergency Operating Procedure l

(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.

F. Unexplained or unplanned reactivity changes.

G. Forced power reduction.

H. - Major personnel injury or radiation overexposure. "

1. Any LCO that would require unit shutdown within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

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 houn.t.

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.

• -p 'f a- w---- e-= .--w3 --T ______ -

• _ _ -v: r -=--+-

_ _ ~ . . . . _ . . . ___ . _ __ _. .. . ___

Pcgo-46.of 1.74 4

ST. LUCIE PLANT

' ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 l CONDUCT OF OPFRATIONS m

~

< APPENDIX F LOG KEEPING (Page 2 of 9)

2. Chronolocical Loos: '

r 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 and complete enough to reconstruct the events of the shift. Particular '

j attention should be made to the entries pertaining to any abnormal condrtion that occurs. Times for each entry snail be as near correct as possible bsing  !

military time. The entries are to be made in chronoiogical order.

i 1. Evolutions, manipulations and operations that are performed, observed

{ and monitored by operators NOT actively assuming the responsibilities of j a particular watch station snail 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.  ;

i 2. When it is necessary to insert additional information after the fact, Then I the entry shall be recorded with the actual time of occurrence, the words ate Entry in parenthesis, and the information to be logged.

l Example: 1234 Started the 1 A EDG for surveillance run i

I 0827 (Late Entry) Filled the 1 A2 SIT with the 1B HPSI Pump in accordance with OP 1-0410021 j 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 j 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 4

tollowing:

a. Conditions at the beginning of each watch.

i

_ _ _ _ - _ . _ ~ _ _ - _ _ . _ _ _ _ _ . _ _ _ _ . _ - . _ _ . _ _ _ _ _ _ _-_ . _ __ _ _

P;ge 4 Tot 174." ...

~

l ST. LUCIE PLANT  !

ADMINISTRATIVF PROCEDURE NO. 0010120 REVISION 79 i

1 f ( >NDUCT OF OPERATIONS 1 APPENDIX F '

LOG KEEPING l (Page 3 of 9) l

2. Chronolooical Loos: (continued)

A. (continued)

4. (continued) ~

b. Significant changes in plant conditions.

Examples: 1. Mode changes.

2. Loao changes.

3. Reactivity changes. l

4. Startups and Shutdown.

5. Time of Reactor criticality.

1

c. Any new condition that would limit unit generation.

Examples: 1. Concenser back pressure at administrative .15.

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.

Pege 70 of 174~

i^

l ST. LUCIE PLANT

! ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 j

CONDUCT OF OPERAVONS APPENDIX M PROCEDURAL COMPLIANCE AND IMPLEMENTATION (Page 1 of 6)

)

l 1. Controlled procedures are available in both Control Rooms and shall be

! implemented and complied with in accordance with the instructions provided in 015 PR/PSL-1,_" Preparation, Revision, Review / Approval of Procedures."

4

, 2. In the event of an emergency where procedural guidance does NOT exist or in '

' which a specific emergency is NOT addressed by an approved procedure, then j

Operations personnel shall take action to protect the health and safety of the public, minimize personnel injury, and damage to the facility.

i i~ 3, Numerous tasks performed by the operators are repetitive and routine in nature.

3 These tasks come under the guidance of the memorization method of adherence to j

procedures in accordance with Ol 5 PR/PSL-1, " Preparation, Revision, j

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 j

trade for qualified operators. Each listed task shall have one or more of the below l justification reasons:

1 1

i (A) Task is routine and not complex - satisfactory completion assured by

routine training and observation.

I (B) Task is routine and has a low level of complexity - satisfactory completion assured by completion of verification checklist and independent venfication; i

i (C) Posted instructions in place as reference.

L (D) Satisfactory completion assured by multiple levels of review and/or

' feedback from system.

4 1-

• A. General Control Tasks i

4

, 1. Racking IN and OUT of 6.9 KV,4.16 KV, and 480V breakers. (B) i

2. Tuming ON and OFF 480V MCC breakers. (D) 2 j 3. Writing clearances and NPWOs. (A,D) a

4 Changing chart paper. (A,D)

I j 5. Placing controllers in MANUAL or AUTO. (A,D) l 4

Page.71 of 174 - -

l S

ST. LUCIE PLANT

' ' ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 79 CONDUCT OF OPERATIONS

1. APPENDIX M

, PROCEDURAL COMPLIANCE AND IMPLEMENTATION (Page 2 of 6) l

1. (continued) -

B. Reactor Control Operator

1. Divert Letdown to Control VCT level. (A,0) '

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 controis). (D)

5. Swapping Auxiliary and Start-up Transformers. (D)

6. Adjusting CEA position (eg. ASI control). (D) 1

7. Manipulation of control valves (ADVs, FCVs) to controi Heatup and Cooldown rates. (D) i l

8. Pumping down Reactor Drain Tank. (A,D)

9. Placing CST on recire. (A,D)

C. Senior Nuclear Plant Operator

1. Generic Rounds Sheets. (A)

2. Swapping HUTS. (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)

i . QI 5-PR/PSL ---

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.~ Revision 6T"" T-

December,1995 Page 92 of 101

! RGURE 4 I RMPORARY CHANGE REQUEST 3 (Page 1 of 3)

A Reference informatton: (Originator to complete)

! St. Lucie Unit # commod TC # o - % - 0 / '/

Procedure

Title:

ecsmc? o e- arceA r, e a s i Procecure Number: 4# oo/0 /2 o Rev. 74

• j Reason for change: ,,u m o cr( m , o c gy vs-- n,arcr. sc s r,s s ve ssPetctetf rc 0 - %, - o / t Originator: o ?A cec Phone: "70G/ Date: / / J $ / 't 6 8 Prececural Controts: (Originator to complete)

} Yes No

O E is tne intece of the procedure attered? (Tecn. Spec. s.s.3.A) If yes, a TC is NOT

applicaole. A PCR is reautred.

O E is this Temporary change for a one-time use? If yes, this TC can be executed one time only. If no, this TC may be used up to 90 days, and the onginator of the TC shall

suomrt a procedure enange request incorporating this TC at the same time the TC is

approved.

Department Head or Designee A / / 2 'I / ## 0

1 O E ts this T.C. for a o.l.? If yes. the Quality Manager or designee and the Dept. Head or i designee wno is junsdictionally responsible for the Q.l. shali sign.  !

Quality Manager or Designee / /

j: Department Heao or Designee / /

C Temcorary chance contents: (Originator to complete)

Does this Change:

Yes No O 9 incorporate complex or extensive changes? If Yes, Subcommrttee required.

Subcommmee Initials O E Modify instrument setpoints?

O 9 Delete an independent venfication?

O E After a OC holdpoint?

O O Modify a procedural step which alters a regulatory requirement as identified in the proceoure?

O S Alter tne first execution of a procedure? (Preop, LO!)

O G Addition of any enemicals?

NOTE pny of the above entena are marked yes. pnor FRG review is required.

/R67

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..QL5-PR/PSL-1 __ ._ ._

Revision 67 ~

December,1995 Page 93 of 101 RGURE 4 I

TEMPORARY CHANGE REQUEST ,

! (Page 2 of 3) )

TC # 0 -96 O/Y I

D to CPR 50.58 Screenang Yes No i '

1. Does me change represent a crienge to me tacity as oescreed in the SAR7

! 2. Does me enange reoresent a enange to proceouros as descnood in tne SAR? .

l 5

3. is tne enange asaccated with a test or expenment not descnood in ins SAR7 /

i t  : 4. Could the enange affect nucisar safety in a way not previous #y eva6uatec in 4

l tne SAR? 7 ,

5. Ooes tne enange roouire a enange to tne Technical Soecificanons? /

. NOTE If the answer to ALL the above 10 CFR 50.59 screening questions are no (Questions 1 5), then a safety evaluation is not recutrea.

STA revow isignaturei YA 5 Date I 'd.((r E Does cms c .ange: (NPS to comsfetei Yes No

1. Comoromise tne seoaranon of redundant trans of sousoment?

2. ?ctentady isonte pressure reliefs? */

3. Cefeat automanc sgnais? /

4. Cefeat ms:naruca or emetncal sntonocus? /

5. Alter tne compteten of an evoluson cue to an operator wonc arounc V If yes to No. 5. autnenzanon from tne Plant General Manager or Site Vice Promoent snad be octainea 1

1 Cate ' ' l Yes No O I Pnor FRG towow rootared?

NOTE If any cf the above entena are rnarked yes, ciscuss possible alternattves with the ong nator. /J,//

NPS Signas,tre #//[/T/ Date /'WN F FnG Recew: ]

Plant General Manager Approval Date ' '_

FRG Numoer -

TNs enange snaN be rewowed (if onor FRG review is not requireo) by tne Facesty Rewow Group and approved by the Plant General Manager within 14 days of the autnonzanon case. (Tech. Spec. 6.5.3.C)

REJECTED by FRG/Ptant General Manager Date _'_'

Reason:

Return to Ong:nator it is tne responmodsty of the onginator of the retected temporary enange to cancel tne enange in the accrocriate Control Room costroy ad field coces ano natt at r.sosecent evolutons using tnts temporary enange.

4

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Reveion 6T ' ~~

December,1995 Page 94 of 101

' RGURE 4 TEMPORARY CHANGE REQUEST l (Page 3 of 3)

G Tc s 0 - %- om Aporovat (This change shall have pnor approval by a NPS and one member of the plant management staff.) (Tech. Spec. 6.8.3.8) l Plant Management Staff Si tur - 2 Pat N[ll ,, Date / /0 7 / 96 NPS Signature [_ Authonzation Date / / z. f i 96 H. Cancellation Authonzation /

(NPS/ANPS) Date /

Reason: I l

-- - - . . . _ _ . . . . . ....._1 Pcge-30 cf 474- l ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 79 CONDUCT OF OPERATIONS APPENDIX B SHIFT OPERATIONS POLICIE,$,

(Page 5 of 8) 1 1

4. (continued)

A. (continued)  ;

4. P - Prove 1

a. Prove to yourself that the actions that were just performed produced j the desired results.

b. Observe and verify the following:

, ' d, 4 1. The. task was performed correctly.

t-  :

g'p 2. The actual response was the expected response.

j

,6

. g. " k] 3. The component / system is in the proper configuration to support the intended operation.

j

.v

4. The proper component was operated.

5. Mi um iviesipulation '

1 N 7 N

.N A. Only licensed operators are3sorutt(tb manipulate the controls that directly affect the rAeacower level of a riactor-excegfor training purposes. A l t ee-mfy manipulate controls only under direct visual supervisQf a licensed operator. _ N )

1

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. l l

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. .T~.7 .-

V TC. C - %, - OI4 APPENDIX B

} SHIFT OPERATIONS POLICIES i

l 2

5. Reactivity Manipulations i

! A. Reactivity manipulations in the course of normal plant operations is defined as the insertion of positive and negative reactivity due to manipulation of the following:

1. CEA insertion and withdrawal.

2. Addition of water and/or boric acid to the VCT or Charging Pumps' suction.

3. Turbine / Generator load changes.

4. Placing a purification ton 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)). '

B. All reactivity manipulations in the course of normal 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.

C. When reactivity manipulations are being performed, both positive and negative, the SRO fulfilling the role of the Control Room Command function shall directly supervise the manipulation and additionally assume the role of a reactivity manager except as provided for in step 6.D.

D. In the event of off-normal and emergency conditions, Reactor Control Operators are authorized to perform reactivity manipulations without the presence of and approval of an SRO, ifin his/herjudgement 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 Room Command function shall be notified of the manipulation as soon as possible.

E.

Crew Relief / Shift Tumover shall NCT take place for Reactor Control ,

Operators or the Assistant Nuclear Plant Supervisor while reactivity mani.9ulations are in progress.

l TC - 9 6, - Of A .

i APPENDIX B j SHIFT OPERATIONS POLICIES l

l

5. (Continued)

- 2 i  !

F. Reactivity manipulations shall be performed only by those individuals i  !

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 l l- in a bonafide training role in pursuit of obtaining a license; they may perform I

' reactivity manipulations under direct visual supervision of a licensed operator with an active license.

I  !

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. . _-- . pyg,g, gig 74 l

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ST. LUCIE PLANT ADMINISTRATIVE PROCEDURE NO. 0010120. REVISION 79 i

CONDUCT OF OPERATONS i APPENDIX D 7 CREW RELIEF / SHIFT TURNOVER ,

(Page 4 of 5)  !

l .

j

1. (continued)

C. Instructions for an Individual Relief / Split-Shift Tumover

1. If a specific watchstation shift is being split ey two individual watchstanders, then the following instructions provide the minimum requirements for shift relief:

a. The off-going watchstancer shall review applicable plant log sheets to

.,s j determine the existence of any off normal condition or trends. 1 v.

,i:b b. The off-going watchstander shall complete the applicable Tumover I Check Sheet (Data Sheet 1) for their watchstation.

6d c. The off-going watchstander shall verbally transmit and explain the

!~ information as recorded on their applicable Tumover Check Sheet s' (Data Sheet 1) to the on-coming watchstander.

c5 -

4 , e, g f. The on-coming watchstander shall review the following and ck acknowledge that review by initialing Check Sheet 1 of AP 1(2)-0010125 " Schedule of Periodic Test, Checks, and x.<

g[F[' Calibrations.'

1. Applicable Watchstation Chronological Log.

2. Applicable Watchstation Operator Log Readings.

3. Night Order Book.

4. NPWO, ANPS. and NWE shall review equipment out-of-service log.

4 f. The applicable unit ANPS shall be notified immediately after the shift J tumover has been completed.

7C D - 9(, - O/'/ ~

l APPENDIX D CREW RELIEF / SHIFT TURNOVER 1.

C.

4 1.

i 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

$ e.

! The on-coming watchstander shall make a chronological log entry indicating he/she has assumed the responsibilities of the watchstation.

1 1 l l

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ST. LUCIE PLANT

ADMINISTRATIVE PROCEDURE NO. 0010120, REVISION 79 l CONDUCT OF OPERATIONS APPENDIX D CREW REllEF/ SHIFT TURN (.WER (Page 5 of 5) i

1. (continued) i D. Instruction for an Interim or Shon Term Relief / Shift Tumover.

i

1. If a soecific watchstander requires a short term relief for a period of less

than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, then the following instructions provide the minimum

requirements for shift relieff

' ^~ 4

' O\

- a. General watchstation status.

l b. Off-normal conditions.

l A

, .jy c. Tests in procress.

s%v

.3'f 2. The applicable unit ANPS shall be notified immediately after the shift g tumover has been completed.

i

/ 3. If an individual is expected to be absent for period of greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, l

./#)N, then an Individual Relief / Split-Shift Tumover shall be performed. l

[

4

. . .- . . - . . =_ .,. .. _. ---------i TC. O - 9 G --- Clk

' ~ ~ ~

! i 4

APPENDIX D CREW RELIEF / SHIFT TURNOVER

1.

D.

i' 1.

4

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 individual assuming their responsibility.

1 1

i e

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m I

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s4'w. .

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/* %., 8

! ~i UNITED STATE 5 -

' 5 / NUCt.AAR REGULATORY COMMIS$10N **

wasuiwetow.o.c. oses

...../

August 28, 1980 -

i .

l NOTE TO: R. Tedesco '

' T. Novak G. Lainas

(

I agree with E. Jordan's memo in that further ,

debate en this issue is probably not warrented 3 at this time. Please ensure that your staff is aware of this interpretation and that this.

• will be the NRC position on this matter at

! this time. .

lj e Darrell G. Eisennut 4

i

~

3 2

Enclosure cc: E. Jorcan [

J. Scinto

]

2 e

4 j

b 4

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• f i

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4 i

4

..-l 9 MCy AL(wan ect1 ,

t0*d 68&STZErer1 01 M '453 *RE _ S@lf-43_-@f_ ___

1 1 - -

~ ~

! UNITED STATit

'[' I g NUCLEAR REGULATORY COMMIS$10N

! +  :.

• WASMtNGTON, o. a. Reese

' Q .

AUG 2 21!S0 55 INS #0200 4

a

?

! HE.MORANDUM FOR: E. J. Brunner, Chief, RO&MSB, RI

! R. C. Lavis, Acting Chief, RO&NSB, RII i R. F. Heishman, Chief , RO&NSB, RIII  ;

j- G. L. Madsen, Chief, RO&N58, RIV  ;

J. L. Crews, Chief, RO&NSB, RV FROM: E. L. Jorcan, Assistant Director for Technical Programs Division of Reactor Operations Inspection, IE i

$UgJECT

DISCUS $ICk 0F " LICENSED POWER LEVEL" (AITS F14580H2) t l l

! Dating back at least t: 1974, there have been many lengthy." discussions" regarding the exact meaning of " full, stency-state licensed power level" (and ,

similarly worded power limits). We do not believe the real safety benefits j that mi;;ht be derived from an NRC wice agreement would be worth the further expenciture of manpower in meetings, etc. that would be required to achieve a l consensus. ,

1 ve de reali:e that some c:mmon uniferm basis for enfercing maximum licensed p:wer is needed by I&E inspect:rs. Therefore, until and unless an NRC-wide position is put fervard and agreec u:en (and as stated, !&E coes not propose to initiate proceedings to that ene), ILE will use the following guidance.

The average power level over any eignt hour shift should not exceed the " full steacy-state licensed power level" (and similarly worded terms). The exact eigns hour ;erieds cefinec as " shifts" are up to the plant, but should not be varied from cay t day (the easias , dafinition is a normal snif t manned by a particular " crew"). It is permissible to briefly exceed the " full, stenay-state licensed power level" by as mucn as 2% for as long as 15 minutes. In no '

case should 107. power be excencec, :et 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 allowee). There are no limits on the numser of times these " excursions" may occur, or the time interval that must seperate such " excursions," exceot note that the above requirement regareing the eight hour average power will prevent abuse of this allowance.

CONTACT: H. W. Woods, IE ,

49-28180

m.a m .

, \

-2 A W 02 7330 I The above is considered to be within the licensing basis and, therefore, acceptante to us, and it is also fair to the utilities and their ratepayers.

. . J roan, Assistant Director for Te ical Programs Division of Reactor Operations Inspection Office of Inspection and Enforcement ec: R. C. DeYoung, IE

$ r M . Bryan, IE isennut, HRR

0. Ross, HRR ,

o O

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g gaa ynr -Q Q- - -

15.2.4 CHIIMICAL EVENT AND VOLUME C0tTTROL SYSTEM MALFUNCTION - BORON

~

15.2.4.1 Identification of Causes -

i The chemical and volume control system (CVCS) described in Section 9.3.4 regulates both the chemistry and the quantity of coolant in the reactor coolant system. Changing the boron conceheration in the reactor coolant

{ system is a part of normal plant operation, compensating for long-ters reactivity effects, such as fuel burnup, xenon buildup and decay, and plant

~

startup and cooldown. - For refueling operations, borated water is supplied l'

from the refueling water tank, which assures adequate shutdown margin. ht '

-ir. advertent boron dilution in any operational mode adds positive reactivity, produces power and possibly temperature increases, and, in Modes ~1 and 2 q

(startup and power operations) can cause an approach to both the DN5R and CTM limits.

• Boron dilution is conducted under strict administrative procedures which specify permissible limits _ on the rate and magnitude of any required change in {

boron concentration. Boron concentration in the reactor coolant system can be I decreased either by controlled addition of unborated makeup water with a corresponding removal of reactor coolant (feed and bleed) or by using the i

deborating ion exchanger. The deborating ion exchanger is normally used for boron removal when the boron concentration is low ((ppm) and the

feed-and-bleed method becomes inef ficient. A boronometer is located in a lihe upstream of the deborating and purification ion exchangers in the CVCS. This

! instrument provides a continuous measure of boron concentration and high-low j- boron concentration alarms, i

J During normal, operation, concentrated boric acid solution is mixed with I Ii domineralized makeup watar to the concentration required for proper plant operation and is autotstically introduced. into the volume control tank in gi response to a low water level signal from the volume control. To effect boron ij dilution, the makeup. controller mode selector switch must be set to " Dilute"

! [

j and the domineralized water batch quantity selector set to the desired (h(i j quantity. When the specific amount has been injected, the demineralizer water control valve is shut automatically. 3 l -

Dilution of the reactor coolant can be terminated by isolation of the makeup

{ vater system, by stopping either the makeup water pumps or the charging pmaps, i.

or by closing the charging isolation valves. A charging pump must be running in addition to a makeup water pump for boron dilution to take place.

5 The CVCS is equipped with the f ollowing indications and alarm f unctions, which I

will inform the reactor operator when a change in boron concentration in the i reactor coolant system may be occurring:

4 a) Boronometer high and low alarms and concentration indication 1

b) Volume control tank level indication and high and low alarms i

1 4

l 1

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l-15.2.4-1 1

_ _ _ _ _ _ _ - _ . . . _ _ _ . _ _ _ _ _ _ . _ _ . _ . ~ _ . _ _. __

^

_ . ['  :~

~

I c) . Makeup flow' indication and alarms 4

d) Volume control tank isolation. ..

Changes in boron concentration while the reactor is on automatic control at full power are compensated for by repositioning the CEA's. Fbwever, to assist i the reactor operator in maintaining an adequate shutdown margin, CEA inserttom l below a position that would provide a minimum of one percent shutdown margin-1- (assuming one stuck CEA) is accompanied by control room alarms.

Because of j the procedures involved and the numerous alarms and indications available to the operator, the probability of a sustained or erroneous dilution is very-low

} 15.2.4.2 Analysis of Effects and Consequences f- 15.2.4.2.1 Method of Analysis s

] .

- The time required to achieve criticality from a suberitical condition due to

} baron baron dilution reactivity is worth, based on andthe theinitial rate and critical boron concent. rations, the of dilution.

due to boren dilution are based on the boron worth and the dilution race. Reactivity inc Cases have been analyzed for all six operational modes. i.e. , power operation, startup, hot standby, hot shutdown. cold shutdown, and refueling.* In each case, it is assumed that the boron dilution results from pumping unborated domineralized water into the reactor coolant system at the maximum possible race of 132 gym (3 x 44 gpm per charging pump) and that the boron concentrations are uniform at all times.

The boron dilution race is calculated by CESEC f or all cases except dilution during refueling.

CESEC described in Section 15.1.4-1 divides the reactor coolant system satisfied into 15 by all nodes. control volumes with the continuity equation being-jfg _ .

content of the system are inputs to CESEC.The charging rate of non-borated water and 4the The maximum dilution rate li (10 5 pps/ minute) occurs at the initiation of the transient. For dilution ,

during refueling the reactor coolant system is assumed to be one control volume with the boron concentration calculated by the time rate of changs o boron equals, flow in times the boron concentration ininus flow out times boron,f.

concentration.

The uniformity of the boron concentration can be assured for the different modes of operation as follows:

a) During refueling Prior to cooldown, the reactor coolant system boron concentration is 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 reactor coolant , it will not precipitat e. The only possible means of obtaining a nonuniform solution is by the addition of domineralized water via the charging pumps. However, because the maximum water

. An additional boron dilution event would be via the Iodine Removal System (NaOH spray additive). This event is not governing, however.

See Reference 42.

15.2.4-2

,a n.A 0- a anu

s. 44u- -,pn.- 4 .s- eae-m .L8,_A,m,aas . ,,,-a4,, , y, a,_ ww _ A eu---.m xwe-t6J20wM i

i i

NRC CLOSED PREDECISIONAL ENFORCEMENT CONFERENCE ST. LUCIE NUCLEAR PLANT AUGUST 19,1996 l

\

$ l Y

NRC CLOSED PREDECISIONAL ENFORCEMENT CONFERErlCE ST. LUCIE NUCLEAR PLANTS AUGUST 19,1996 IAB TITLE 1

Predecisional Enforcement Conference Agenda 2 Expected Attendees, Meeting Announcement -

3 Opening Remarks and Introductions 4 NRC Enforce' ment Policy 5 Summary of the issues 6 Statement of Concerns / Apparent Violations 7 Inspection Report No. 50-335/389/96-12 8 Enforcement Pre-Panel Questionnaire (Configuration Management) 9 Fnforcement Pre-Panel Questionnaire (10 CFR b0.59 Safety Evaluations) 10 TIA Response on FPL Safety Evaluation for EDG Fuel Line Isolation 11 Closing Remarks i

l a

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PREDECISIONAL ENFORCEMENT CONFERENCE AGENDA j l

l

., ST. LUCIE

. AUGUST 19,1996, AT 1:00 P.M. 1 NRC REGION 11 OFFICE, ATLANTA, GEORGIA-4 s

j' I

!. OPENING REMARKS AND INTRODUCTIONS 5

L. Reyes, Deputy Regional Administrator i ll. NRC ENFORCEMENT POLICY  ;

B. Uryc, Director l

Enforcement and Investigation Coordination Staff l 111.

SUMMARY

OF THE ISSUES L. Reyes, Deputy Regional Administrator

{

IV. STATEMENT OF CONCERNS / APPARENT VIOLATIONS i

J. Jaudan, 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 1

w J Licensee i j

l 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 l

, NRC L. Reyes, Deputy Regional Administrator, Region 11 (Rll) -

J. Jaudan, Acting Deputy Director, Division of Reactor Projects (DRP),

Ril A. Gibson, Director, Division of Reactor Safety (DRS), Ril  ;

8. Uryc, Director, Enforcement and Investigation Coordination Staff ,

(EICS), Ril -

C. Casto, Chief, Engineering Branch, DRS, Rll '

K. Landis, Chief, Reactor Projects Branch 3, DRP, Ril C. Evans, Regional Counsel, Ril j M. Miller, Senior Resident lnspector, St. Lucie, DRP, Ril E. Lea, Project Engineer, Reactor Projects Branch 3, DRP, Ril L. Mellen, Project Engineer, Reactor Projects Branch 3, DRP, Ril l

I I

l

OPENING REMARKS AND INTRODUCTIONS (L. Reyes) w Good morning. I am Luis Reyes, Deputy Regional Administrator for the Nuclear Regulatory Commission's Region ll Office. This morning we will conduct a predecisional enforcement conference between the NRC ,

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 ll Enforcement Staff, will discuss the Agency's Enforcement Policy. I will then provide introductory remarks concerning my perspective on the events to be addressed today. Johns Jaudon, Acting Deputy Director of the Division of Reactor Projects, will then discuss the apparent violations. You will then be given an cpportunity 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

. l will be taken. This conference is an important step in arriving at that decision. l l

Following your presentation, I plan to take about a 10-minute break so -

I that the NRC can briefly review what it has heard and determine if we have follow-up questions Lastly, I will provide concluding remarks.

i i

4 At this point, I would like to have the NRC staff introduce themselves i

and then ask you to introduce your participants.

1

[lNTRODUCTIONS]

Thank you.

Mr. Uryc will now discuss the Agency's Enforcement Policy.

l d

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l NRC ENFORCEMENT POLICY i ,

(B. Uryc)

NRC Enforcement Policy and Procedure After an apparent violation is identified, it is asse'ssed 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, i

The_ assessment of an apparent violation involves categorizing the ,

i apparent violation into one of four severity levels based on safety and l 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 Level I,11, or Ill, a

predecisional enforcement conference is held.

i 4 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, l' because of a significant public health or safety issue.

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! .This predecisional enforcement conference is essentially the last step i

of the inspection or investigation process before the staff makes its l .. final enforcement decision, o

l 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 l

opportunities associated with the violations, (2) a common l understanding of corrective action taken or planned, and (3) a common understanding of the significance of issues and the need for lasting comprehensive action.

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l 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 conduct this conference does not mean that NRC has determined that a violation has occurred or that enforcement action will be taken.

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' I should also note at this time that statement of views or the ,

1 expression of opinion made by the NRC staff at this conference, or the I /ack thereof are not intended to represent final determinations or beliefs.

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{' 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 l i

i about four weeks to accomplish, i

Predecisional enforcement conferences are normally closed to the j public as is this conference. However, the Commission implemented a ,

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i trial program in July 1992 to allow certain enforcement conferences to i I

be open for public observation. [ July 10,1992 - Federa/ Register) j 4

This trial program was recernly extended for additional evaluation.

. Finally, if the final enforcement action involves a proposed civil penalty

or an order, the NRC will issue a press release 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the enforcement action is issued.

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SUMMARY

OF THE ISSUE.

(L. Reyes) 1 Issues: 50.59 Safety Evaluations and Configuration Management 1 l

Process ,

I This is a Predecisional Enforcement Conference to discuss apparen,t 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 l

concern because it indicates that deficiencies have existed in configuration management processes which have manifested

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themselves in failures to ensure that the design of the plant was

, properl_y incorporated into plant procedures and, to a lesser degree, l

l drawings. No plant event has been tied to the inaccuracies thus far l 4

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identified; however, we are concerned about the potential extent of l-these conditions.

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STATEMENT OF CONCERNS / APPARENT VIOLATION y (J. Jaudon)

Issue: Configuration Management Several examples of failures to properly incorporate design changes or ,

constraints into plant procedures and drawings were identified.

Defect:

The apparent violation included five examples :

1) 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 (PC/M).

2) One example of a failure to update an engineering drawing to reflect the deletion, via PC/M, of valves and piping for intake Cooling Water (ICW) System Pump Lubrication. ,

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3) One example of a failure to update an annunciator responce i

summary to reflect a change, made via PC/M, which removed automatic and control room operation capability i from a pair of ICW valves.

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4) One example of a failure to update an annunciator response

! procedure to reflect a change, made via PC/M, which removed the alarm function when placing Atmospheric Steam Dump Valve Selector Switches in manual.

5) 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 PC/M which included a spent fuel pool heat -

load calculation, l

The apparent violation identified above has been determined to be similar to annunciator response summary deficiencies identified in l previous inspection reports. As a result, we are concerned that the extent of condition of configuration management deficiencies may not ]

yet be known.

Consequences: I The failures to update annunciator response procedures and drawings following PC/M implementation resulted in providing inaccurate or

I-i misleading information to control room operators. In the case of not c

properly incorporating the spent fuel pool heat load calculation into l

l operational procedure limitations, a full core off-load was commenced l

without verifying or establishing appropriate parameters.

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STATEMENT OF CONCERNS / APPARENT VIOLATION y (J. Jaudon)

Issue: 50.59 Safety Evaluations NRC inspectors reviewed several safety evaluations or issuee which potentially required safety evaluations. Problems were identified with four of the items reviewed. The items of concern spanned the areas of whether changes were properly considered for applicability under 10 CFR 50.59, the adequacy of 50.59 screenings, and conclusions reached during 50.59 evaluations.

Defects / Consequences:

The apparent violations, and their associated consequences, are as follows.

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1) A fai!ure to perform a safety evaluation for the construction of the Unit 2 CEDMCS room was identified. The room had i

1 been constructed during the preoperational test phase of the unit and this failure was identified in June 1996.

Upon conducting an evaluation of the room, it was identified that modifications to supports and restraints for non-safety-related components were required to ensure that the subject components did not adversely affect safety-related components during a seismic event.

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 resulted in a change to the P&lD for the fire protection l

system provided in the UFSAR and the pump's capacity was lower than that for the pump it replaced.

i The consequences of this action were that a safety evaluation of the proposed alteration's impact on an operable plant system was not performed.

3) The '10 CFR 50.59 screening process failed to identify that .

refueling machine underload and overload setpoints were included in the UFSAR. This led to a failure to perform a required safety evaluation.

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 recommending approval. l

4) An example of a f ailure to recognize an unreviewed safety i

question was identified. in making a valve lineup change to I

the EDG fuel oil transfer system, reliance on operator action replaced automatic action and introduced new f ailure modes to the EDG. 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 f ailure, prior NRC approval was not obtained for the change in question.

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t Our findings are documented in NRC Inspection Report 50-335, j 389/96-12, which were transmitted to you on July 26,1996. At this conference, we are affording you the opportunity'to provide d

information relative to:

4 e Any errors the inspection reports -

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i j e The severity of the violations l e Any escalation or mitigation considerations  !

e Any other application of the Enforcement Policy relevant to this 1

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1 ISSUE TO BE DISCUSSED 10 CFR 50 Appendix B, " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," Criterion lil requires, in part, that j measures be established to assure that applicable regulatory  !

requirements and the design basis for those structures, systems, and i components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions.

1. 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 l revised. This resulted in annunciator S-10, "HYDRAZINE TK LEVEL LO," showing an incorrect setpoint o'f 35.5 inches in the procedure.

2. During implementa' tion 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 I-FCV-21-3A & 3B and associated piping still installed.

3. PC/M 268-292 [lCW 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.

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4. 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/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. l l The relay contacts which energized these annunciators based on j switch position were removed to eliminate nuisance alarms.

5. The licensee failed to incorporate the prerequisite conditions

contained in PC/M 054-196, supplement 0, "St. Lucie Unit 1 l Cycle 14 Reload," into OP 1-1600023," Refueling Sequencing

Guidelines." As a result, requirements for the operation of two l Spent Fuel Pool Cooling Pumps, maximum initial Spent Fuel Pool o '

temperature, minimum time since shutdown, minimum l Component Cooling Water system flow to the Spent Fuel Pool i heat exchangers, and operability of control room annunciation l were not verified prior to the initiation of fuel offload.

i NOTE: The apparent violations discussed in this predecisional

- enforcement conference are subject to further review and 1 are subject to change prior to any resulting enforcement I decision.

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1 ISSUE TO BE DISCUSSED 10 CFR 50.59, " Changes, Tests and Experiments," stated, in pact, 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, and that the licensee shall maintain records of changes in the f acility.

1. 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.

2. The licensee erected an enclosure around the Control Element Drive Mechanism Control System during the Unit 2 preoperational test phase without performing a safety evaluation. This non-safety related structure was erected in a safety related cable spread room.

3. 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 required safety evaluation.

4. 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.

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.

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l. i July 26, 1996 EA 96-236 & EA 96-249 )

i Florida Power & Light Company  ;

ATTN: T. F. Plunkett  !

l President - Nuclear Division P. O. Box 14000 .

Juno Beach, Florida 33408-0420 l

SUBJECT:

NRC SPECIAL INSPECTION REPORT 50-335/96-12, 50-389/96-12 l

Dear Mr. Plunkett:

On July 12, 1996. the NRC completed a special inspection of engineering l activities at your St.'Lucie 1 and 2 facilities. The enclosed report presents the results of that inspection. Areas examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, plant drawings, and engineering evaluations.

l Based on the results of this inspection, five apparent violations were

! identified and are being considered for escalated enforcement action in accordance with the " General Statement of Policy and Procedure for NRC i Enforcement Actions" (Enforcement Policy), NUREG-1600.

4 One of the apparent violations is of concern because it indicates that  !

deficiencies have existed in your configuration management processes which l have manifested themselves in failures to ensure that the design.of the plant was properly incorporated into plant procedures and, to a lesser degree, drawings. While no plant event has been tied to the inaccuracies thus far identified, we are concerned about the potential impact of inaccuracies which j may not yet have been discovered.

l- In addition to configuration management issues, four apparent violations were identified in the area of preparation of safety evaluations under 10 CFR l 50.59. These apparent violations are of concern because they indicate that i

weaknesses exist in both recognizing the need for safety evaluations and in j the process applied in assessing the impact of changes upon the plant.

l A predecisional enforcement conference to discuss these apparent violations l has been scheduled for August 19, 1996. The decision to hold a predecisional enforcement conference does not mean that the NRC has determined that a violation has occurred or that enforcement action will be taken. This conference is being held to obtain information to enable the NRC to make an enforcement decision, such as a common understanding of the facts, root causes, missed opportunities to identify the apparent violations sooner, i corrective actions, significance of the issues and the need for lasting and effective corrective actions. In addition, this is an opportunity for you to point out any errors in our inspection report and for you to provide any l

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FPC 2 1 information concerning your perspectives on 1) the severity of the violations, -J

2) the application of the factors that the NRC considers when it determines ,

the amount of a civil penalty that may be assessed in accordance with Section .i VI.B.2 of the Enforcement Policy, and 3) any other application of the ,

Enforcement Policy to this case, including the exercise of discretion in l accordance with Section VII.

You will be advised by separate correspondence of the results of our

, deliberations on this matter. No response regarding these apparent violations l

! is required at this time.

In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of l this letter and its enclosures will be placed in the NRC Public Document Room J (PDR). )

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Sincerely, l 4 Original signed by Jon R. Johnson I Jon R. Johnson, Acting Director Division of Reactor Projects

Docket Nos. 50-335, 50-389

License Nos. DPR-67, NPF-16 I

Enclosure:

Inspection Report 50-335/96-12, 50-389/96-12

cc w/ encl

I J. A. Stall i Site Vice President  ;

St. Lucie Nuclear Plant P. 0. 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 J. Scarola Plant General Manager St, Lucie Nuclear Plant P. O. Box 128 Ft. Pierce, FL 34954-0128 cc w/enci cont'd: (See page 3) 4

FPC- 3 cc w/ encl: Continued E. J. Weinkam l

Plant Licensing Manager ,

1- 2St. Lucie Nuclear Plant P. O. Box 128 Ft. Pierce, FL 34954-0218 J..R. Newman, Esq.

Morgan, Lewis & Bockius 1800 M 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 Joe Myers, Director Division of Emergency Preparedness Department of Community Affairs 2740 Centerview Drive Tallahassee, FL 32399-2100 Thomas R. L. Kindred County Administrator St. Lucie County 2300 Virginia Avenue i l

Ft. Pierce, FL 34982 4 Charles B. Brinkman l Washington Nuclear Ooerations ABB Combustion Engineering, Inc.

12300 Twinbrook Parkway, Suite 3300 l Rockville, MD 20852' l Distribution w/ encl: (See page 4) 1 l

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Distribution w/ encl:

K. D. Landis, RII

.J. A. Norris, NRR i B. R. Crowley, RII -

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- G. A. Hallstrom, RII-l W. H. Rankin, RII S. H. DuBose, RII PUBLIC ,

I NRC Resident Inspector U.S. Nuclear Regulatory Comm.

7585 South Highway A1A l Jensen Beach, FL 34957-2010 l

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• See previous ncurrence - attached i, nrrtr r n!i ndp mit app pit .nn s nenog nei.nM mii rian q SIGNATURE h * *

• ELee.dk a MMeller WMdler .JYork hB NAME OATE 07 ' 96 07 96 07 96 17 96 07 '96 l 07 /96 j '

COPY? YES rJO VES tJo i *ES '40 l vis 'JO [Ep fJO l [ES) NO V

OFFICIAL RECORD CCPT- DOCUMENT NAME: At\SL9612.ENG I

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.FPC 4 1

' Distribution w/ enc 1:

K. Landis, RII J. Norris, NRR  ;

'B. R. Crowley,'RII r

G. ' A. Hall strom, RII

-PUBLIC NRC Resident Inspector. ,

U.S. Nuclear Regulatory .Com.

7585 South Highway A1A -

Jensen Beach, FL 34957-2010-I

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O FFf rF R11 amp Rf t-nRD Rif-mRR Alt NRR Rff nRP SIGNATURE

[ JJohnson i NAME Eles:oka MMiller WMil r JYoe

. 4 07 r /4 8 96 07 the 96 07 ' } '96 07 ' t96 DATE 07 t/9

• 96 '07'/4196 COPY 7 YES *JO YES NO YES NO M NO lkY h ' NO "

YES NO 0FFICIAL RECORD GPY JOCUMENT NAME: A:\lR9612.ENG l

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I U.S. NUCLEAR REGULATORY COMMISSION

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REGION II .1 1 1

b. l 3 .

l 1 Docket Nos: 50-335. 50-389

' License.Nos: DPR-67, NPF-16 (

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, Report No: 50-335/96-12, 50-389/96-12 ,

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Licensee: Florida Power & Light Co.

l, Facility: St. Lucie Nuclear P.lant. Units 1 & 2 1

I Location: 9250 West Flagler Street l Miami FL 33102 i

Date: July 12, 1996 1

- Inspectors: M. Miller, Senior Resident' Inspector

• W. Miller, Resident Inspector (acting)

J. York, Reactor Inspector J

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l Approved by: K. '_andis

L Chief. Reactor Projects Branch 3

' Division of Reactor Projects j 4

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EXECUTIVE

SUMMARY

St. Lucie Nuclear Plant, Units 1 & 2 NRC Inspection Report 50-335/96-12, 50-389/96-12 This special inspection included aspects of licensee's configuration management and 10 CFR 50.59 programs. Specifically, the inspection examined the extent to which plant changes were appropriately incorporated into procedures and drawings and the performance of 10 CFR 50.59 safety evaluations. Conclusions included the following:

• A review of a number of screenings and evaluations performed pursuant to 10 CFR 50.59 resulted in the identification of four apparent violations:

= One example of an apparent failure to perform a safety evaluation due to a failure to employ engineering controls in the construction of the Unit 2 Control Element Drive Mechanism Control System room and a continuing failure to recognize the nondocumented nature of the room (paragraph E1.1.b.1).

• One example of an apparent failure to identify that the installation of a temporary fire pump represented a change to the plant as described in the Update Final Safety Analysis Report, resulting in a failure to perform a safety evaluation (paragraph El.1.b.2).

- One example of an apparent failure to recognize that refueling equipment setpoints were included in the Updated Final Safety Analysis Report while performing a safety evaluation screening, leading to a failure to perform a safety evaluation (paragraph E1.1.b.3).

- One example of an apparent failure to recognize an unreviewed safety question in the development of a safety evaluation for an Emergency Diesel Generator fuel oil transfer line valve lineup change (paragraph El.l.b.4).

. A review of off-normal operating procedures relating to safety-related annunciators identified a number of inaccuracies (paragraph E7.1).

- Five apparent failures to properly incorporate Plant Change / Modification packages into drawings and procedures were identified (paragraph E7.2).

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1 Report Details El Conduct of Engineering 1

El.1 Safety Evaluations /10 CFR 50.59 Issues (37550. 71707)

a. Inspection Scope The inspectors reviewed a sample of the licensee's safety evaluations (SEs) performed pursuant to 10 CFR 50.59. The evaluations were reviewed for threshold for determining if an unreviewed safety question (USQ) existed because of an increase in the probability of a design basis accident occurring, an increase in equipment malfunction, a reduction in the margin of safety, or an increase in radiation dose consequences.

These evaluations were also reviewed for adequacy of screening and assumptions used for the safety evaluations. )

b. Observations and Findings j The inspectors reviewed twelve SEs or issues which might require SEs. l The issues were -

• Cracking of Westinghouse Alloy 600 Mechanical Steam Generator Plugs. )

• Temporary Relocation of Class Break on Intake Cooling Water.

• Installation of Temporary Fire Penetration Seals in Pipe Barrier BWO64.

. Temporary Installation of Strain Measuring Devices on the Pressurizer Relief Valve Discharge Piping.

- Safet , jection Tank (SIT) Discharge / Loop Check Valve Stroke Test s 1

. . Freeze Seal Application for V3651 and V3652 on the 18 Shutdown Cooling Return Line.

. Safety Evaluation For Boraflex Blackness Testing Results.

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= Wide Range Nuclear Instrumentation Temporary System Alteration.

. Temporary Configuration for Control Element Drive Mechanism Control System (CEDMCS) Cooling System and Enclosure. Unit 2.

- Safety Evaluation for inoperable Fire Pump

- St. Lucie Unit 1 Refueling Equipment Underload and Overload  ;

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. The Isolation of Fuel Oil Supply Line to the 2B Emergency Diesel l Generator.

Problems were identified with the last four items and tne details are discussed in the following paragraphs.

1) Temporary Configuration for CEDMCS Cooling System and Enclosure On June 4, 1996, a control room annunciator indicated that an undervoltage condition existed on the CEDMCS. Operations responded to the CEDMCS equipment and noted that the CEDMCS enclosure was approximately 11 degrees warmer than normal. This ,

enclosure is located in the cable spreading room on the 43 foot elevation of the reactor auxiliary building.

Following this event, an in-House Event Report and Condition Reports (CRs) 96-1238. 96-1245 and 96-1325 were issued. The following items with appropriate plant corrective action tracking numbers were identified by these reports:

• CEDMCS enclosure and air conditioning did not appear on the plant's controlled drawings. (S 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 CR 96-1325, a 10 CFR 50.59 safety evaluation was performed on the CEDMCS enclosure. The evaluation l

' found that this air conditioned enclosure was erected in the early 1980's during the pre-operational testing phase. Testing performed at that time found that the CEDMCS enclosure required an air conditioned environment to prevent overheating of the four CEDMCS cabinets. The licensee's current review determined that the design of the enclosure was acceptable. except that the air i 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 l

conditioning units and duct prior to the unit's restart on June j 13.

l The inspector reviewed the 10 CFR 50.59 SE prepared for the design and installation of the seismic restraints and justification of the installation of the CEDMCS enclosure. A 10 CFR 50.59 review was 4pparently not performed when the enclosure was originally '

erected. The CEDMCS was described in the Updated Final Safety Evaluation Report (UFSAR) but the cooling system and enclosure for the CEDMCS were not described in the UFSAR. This was identified  !

as another example of Unresolved Item (URI) 50-335,389/96-04-09,

" Failure to Update UFSAR."

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The failure to perform an evaluation as required by 10 CFR 50.59-prior to, or at any time subsequent to, makir.g a change to the plant as described by the UFSAR is an apparent violation (EEI 50-389/96-12-01, " Failure to Perform a 10 CFR 50.59 Safety Evaluation for.CEDMCS Enclosure." EA 96-236).

2) Safety Evaluation for Inoperable Fire Pump During the Spring 1996 Unit I refueling outage, one of the two Unit 1 Emergency Diesel Generators (EDGs) had been placed out of 3 service to perform maintenance and modification work activities.

Only one EDG was in service to provide power in the event of a loss of offsite power event. To prevent a possible overload on the single EDG unit, a number of breakers to various components were opened and the units 480V electrical busses were crosstied in accordance with OP 1-0910024, Rev 6, "Crosstying/ Removal of 480V Buses." One of the components removed from service was Fire Pump 1B. The breaker to this fire pump was opened on May 21, and this pump was removed from service and remained out of service on June 8.

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, the inoperable equipment was to be restored to service within seven days or an alternate backup pump was to be provided within the next 30 days.

Fire Pump 1B had been out of service for 18 days. The l

compensatory measure established for this pump being out of service was the installation of a portabl.e 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 l

i the two required pumps and a justification was not provided to l

demonstrate that this pump was of adequate capacity to meet the ,

l maximum fire flow requirement for the safety related areas of the l l plant. The licensee initiated a CR to review this item.

t 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 an alternate backup pump had not been exceeded. This met the i requirements of AP 1800022 for one pump being inoperable. l Resolution of CR 96-!!56 indicated that the installation of the  !

portable fire pump as the compensatory measure with one of the i permanently installed fire pumps out of service was performed without an engineering evaluation to ensure adequate capacity and without a review under 10 CFR 50.59. The inspector found that the l installation of the temporary pump resulted in a change to the o

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! plant as described in the UFSAR, Figure 9.2-5, " Flow Diagram Fire Water, Domestic & Makeup Systems." The inspector concluded that a safety evaluation should have been prepared to justify and document the temporary configuration. The licensee stated that no 10 CFR 50.59 screening (and nence, no evaluation) was performed for this installation because the temporary pump, and its associated piping, was installed via Work Order, with no pre-approved procedure and outside the licensee's Temporary System Alteration process (which, if exercised, would have required a safety screening / evaluation). This is an apparent violation (EEI 50-335,389/96-12-02, " Failure to Perform a 10 CFR 50.59 Safety Evaluation For Use of a Temporary Fire Pump," EA 96-236).

3) Refueling Equipment Overload and Underload Settings CR 96-812 was issued on the SE SEFJ-96-020 by 'the licensee. The report stated that an engineering evaluation had been written to modify the overload and underload setpoints described in the UFSAR without performing a 50.59 safety analysis / evaluation. These overload and underload 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.

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 of the weight of a fuel assembly to 18 percent (approximately 200 pounds). The original engineering analysis did not take into account that these changes ,

in setpoint values would affect the UFSAR and thus the CR was l' 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

.caluations. This procedure references QI 2.1, "10 CFR 50.59 Screening / Evaluation," Rev 1 dated March 30, 1996, which stated, in part. that the screening process was designed to determine 1 whether an activity required a complete 10 CFR 50.59 by asking a series of four questions. One ouestion. "Does the change represent a change to procedures as described in the SAR7" should have been answered "yes" in the case of the original engineering analysis. The procedure also stated that, "A positive response to any of the first four... questions regr. ires a 10 CFR 50.59 1 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 precedure to the engineering group for correction and the CR was written to identify the problem. This failure to perform an evaluation as required by 10 CFR 50.59 prior to making a change to plant procedures described

5 in the UFSAR is an apparent violation (EEI 50-335/96-12-03,

" Failure to Perform a 10 CFR 50.59 Safety Evaluation For Change in Setpoints Listed in UFSAR," EA 96-136).

4) Safety Evaluation for Closing Manual Valve to EDG Fuel Supply in July, 1995, the inspector reviewed SE JPN-PSL-SENS-95-013, which was prepared to allow operation with a manual isolation valve closed in the 2B EDG fuel oil (F0) line from the Diesel Fuel Oil Storage Tank (DFOST) 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 the environment until the leak could be identified and corrected.

As a compensatory measure, the licensee proposed dedicating a Non-Licensed Operator (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 FO 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 open the valve within 20 minutes of an EDG st>.r . 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 i 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 seven minutes.

In considering the issue, the licensee employed Probabilistic Risk Assessment (PRA) techniques to estimate the increase in the risk of the loss of the 283 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.

The inspector noted that 10 CFR 50.59 was written in terms of absoTute 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

6 mitigated). The inspector concluded that insufficient guidance existed from a 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 the question to the Office of Nuclear Reactor Regulation for resolution.

After consideration of the issue, the NRC determined that 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 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, represented a US0, as defined in 10 CFR 50.59. Consequently, this action is identified-as an apparent violation (EEI 50-389/96 04, "Unreviewed Safety Question involving EDG 2B," EA 96-236). <

c. Conclusions on Conduct of Engineering The inspectors concluded that four apparent violations relating to CFR 50.59 safety evaluations existed. The inspectors noted that these issues varied both in vintage and in individual detail. Summarizing, the examples were the result of:

I

1) One example of a failure to perform a safety eval'uation due to a  :

failure to employ engineering controls in the construction of the Unit 2 CEDMCS room and a continuing failure to recognize the nondocumented nature of the room.

2) One example of a failure to i6entify that the installation of a temporary fire pump represented a change to the plant as described in the UFSAR. resulting in a failure to perform a safety j evaluation.

3) One example of a failure to recognize that refueling equipment setpoints were included in the UFSAR while performing a safety evaluation screening, leading to a failure to perform a safety evaluation. This example was identified by the licensee and corrected before any actual change took place.

4) One example of a failure to recognize an unreviewed safety question in the development of a safety evaluation for an EDG fuel oil transfer line valve lineup change.

E7 Quality Assurance In Engineering Activities

a. Inspection Scope During the week of May 20, the inspector performed a walkdown of the Unit 1 Plant Auxiliary Control Board (PACB) safety-related annunciators

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LA and LB to verify the accuracy of annunciator response procedures.  !

This consisted of a review of the following procedures and engineering drawings, including:

e ON0P.2-0030131, Rev 51, " Plant Annunciator Summary" j

. Other~ Procedures

. . Applicable Engineering Drawings

. UFSAR Section 7.5

b. Observations and Findings As a result of the walkdowns, the following discrepancies were noted:

Procedure Attribu*e Erroneous Attribute Correct Attribut; ONOP 2 0030131, Annunciatre LA 6 Indicated Conottion "C" Indicated Condition "Ca Rev 51, " ATMOS STM JUMP ISOL " Feeder breater open to "Feeoer breaker open to

" Plant Annunciator VALVES MV-0'r 15, Mv 08- MV-08-15 or 16" MV-08 15 or 17" Sunnerya 17 MOTOP WERLOAD VALVES CLOSED" Annunciator LA 9 "0IESEL Sensing Elements listed LS-59 9A and 14A Olt DAY TANKS 2A1, 2A2 as LS 59-006A and 10A LOW LOW LEVEL" Annunciator LA 12 Indicated conditions, This indicated "ATM SIM DUMP MV CWD reference and condition and contacts 18A/188 OVERLOAD /SS sensing element were removed by PC/M ISOL" 275 290, closed 10/28/92 Annunciator LB-9 " DIESEL Sensing Elements listed LS 59-0218 and 0268 O!L DAY TANKS 281, 282 as LS 59 0188 anc 0248 LOW-LOW LEVEL" Annunciator LB 14 Sensing Element TA 4421 *

" FUEL POOL HIGH/ LOW not listed LEVEL HICH TEMD" LB-10 Sensing Element ooes not

" COMPONENT COOLING WTR specify contact 71X SURGE TANK HIGH LEVEL COMPARTMENT B LOW LEVEL" Annunciator LB 11 Sensing Element listed Sensing Element should

" PRESSURIZER LO Lo LEVEL as LC 1110X be LA-1110x CHANNEL Y" Annunciator LB 12 Indicatea conoitions, This indicated "ATM STM DUMP MV 08- CWD reference and condition and contacts 19A/198 OVERLOAD /SS sensing element were removed by PC/M ISOL" 275-290, closed 10/28/92 Drawing 2998 B 327 Does not show wnich LA Sheet 211, Rev 14, annunciator alarms from

" Component Cooling LS 14-1A water Shutoown Heat Each & Surge Tank Fitt valves"

- . -- - - - . . .-. . -.~. ~ . . - - .- _ - - . . . ~ .. - - - . - , - . . ...

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2998 8 327 ' Annunciator LA-9 sensing Element sensing Element should e sheet 1142, Rev 7, specified as LS*17 552A, be LS 59 009A, 14A 4 " Plant Auxilleries $53A Control Board

. Annunciator LA" 2998 B 327 Annunciator LB 9 Sensing Element sensing Element should

Sheet 1143, nov 7, specified as LS-17 5528, be LS 59-021B, 0288

" Plant Auxiliaries 5538 Control Board

. Annunciator - LB" The inspector noted that the errors above were additional examples of .

errors identified in previous inspection reports which had been l documented under URI 96-04-05, " Configuration Control Management." The  !

l. inaccuracies noted were consistent with inaccuracies identified in i

previous, similar, walkdowns. The inspector noted that two inaccuracies ',

(annunciators LA-12 and LB-12) were clearly the result of the inadequate implementation of the design change process. These inaccuracies are discussed in the context of other, similar, inaccuracies in paragraph E7.1, below.

c.. Conclusions The inspectors concluded the following with respect to annunciator  ;

panels LA and LB for the PACB:

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. Annunciator response procedure inaccuracies existed of the same types identified in previous, s%ilar, walkdowns.  ;

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. In the cases of two annunciator windows, the inaccuracies were '

identified to be the result of inadequate implementation of tha design change process.

E7.2 PC/M Execution Issues (71707. 37551. 92901. 92903)

a. Inspection Scope Inspection Report (IR) 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 inadequa:y in the' implementation of a PC/M. URI 96- 1 04-05, " Configuration Control Management," was opened to track the issue l while the inspection scope was expanded. IR 96-06 documented additional deficiencies, identified during system walkdowns, which were the result of PC/M implementation' inadequacies. During the current inspection period, two additional PC/M implementation issues were identified; one, involving inaccuracies in annunciator response summaries, is described in paragrapn E7.1, above; one, involving licensee-identified procedural inadequacies, is described below. The inspectors performed a review of the relevant inspection findings in an attempt to characterize the identified issues.

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b. Findings The inspectors reviewed issues identified under URI 96-04-05,

" Configuration Control Management." IR 96-06 summarized recent NRC findings in the area of inaccuracies in plant procedures and drawings and stated that ten examples of alarm setpoint inaccuracies and 18 other (e.o. wrong sensing element, wrong action directed) inaccuracies in the Annunciator Response Summaries had been identified in both units' ICW j and CS systems. The inspectors reviewed findings generated in irs 96- )

04, 96-06, and the current reporting period to identify examples which  !

demonstrated that design changes made to the plant resulted, through inadequate implementation, in such inaccuracies. As a result, the .

inspectors identified the following items: l

1) IR 96-04 documented the fact that, on January 6, 1995, the  ;

licensee closed out PC/M 109-294 [Setpoint change to the Hydrazine l 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 LO," showing an incorrect setpoint of 35.5 inches.

2) IR 96-06 documented the fact that, on May 16, 1994, the licensee l 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 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. l 1

3) 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 to verify the position of valves MV-21-4A & 4B following a Safety Injection Actuation System (SIAS) signal using control room )

indication. These valves no longer received a SIAS signal, were deenergized and had no control room position indication.

4) This inspection report (paragraph E7.1) documents the fact that, on October 28, 1992, the licensee closed out PC/M 275-290 [FIS 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/18B OVERLOAD /SS ISOL," and "LB-12 ATM STM DUMP MV-08-19A/1SB 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

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alarms.  !

In addition to these findings, the licensee identified one example of a l failure to include operational limitations imposed by a calculation in a plant procedure:

4 I

5) During the current inspection period, the licensee identified the l fact that assumptions made in the heat load calculation supporting l

-the Unit 1 full core offload were not appropriately factored into 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 4

included:

• Ensuring that initial Spent Fuel Pool (SFP) temperature was less than or equal to 106 F.

• Ensuring that the reactor was subcritical for at least 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> prior to commencing the offload.

• Verifying that the SFP high temperature alarm, which annunciated in the control room, was operable.

!

• Verifying that two SFP cooling pumps were in operation.

t

• Verifying that Component Cooling Water (CCW) flow to the a fuel pool heat exchangers was maintained at approximately r 3560 gpm when two SFP cooling pumps were operating.

4 On May 12, the licensee's Quality Assurance (QA) organization identified the fact that these limitations were not included in 0F 1-1600023. " Refueling Sequencing Guidelines." The ' offload of seven fuel assemblies had occurred by the time the deficiencies were identified. The defueling evolution was subsequently stopped, and the prerequisites were added to OP l-1600023,

" Refueling Sequencing Guidelines," as revision 62 to the procedure.

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, Rev 11, " Design Control,"

included the following provisions:

• Section 3.2 2, " Design Change Control," stated, in part, " Design ,

changes shall be reviewed to ensure that implementation of the l design change is coordinated with any necessary changes to ,

operating procedures..."

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• 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 meet the criteria of 10 CFR 50 Appendix B and the licensee's QA program. The inspectors found thst the number of examples identified indicated that a programmatic flaw existed in the licensee's program for ensuring that material changes to the plant were reflected properly in engineering drawings and plant procedures. As such, the issues above were found to constitute five examples of one apparent violation (EEI 50-335,389/96-12-05, " Failure to Ensure Configuration Contrci," EA 96-249).

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.

• Plant procedures and instructions did not adequately address the review of Safety Evaluations for impact on plant procedures and instructions (this applied to Safety Evaluations whicn 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:

. Implementing design control processes from Turkey Point, which provided more positive cor. trol over the initial reviews and docurnentation of required actions for PC/Ms.

. Performing reviews of all Unit 1 outage related PC/Ms to ensure that required procedural changes were identified.

. 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.

. Revalidating open items from previous PC/Ms on both units and establishing timelines for closure of the open items.

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! 12 1

= Initiating a vertical slice inspection of selected, PRA- )

significant systems to ensure that the systems were properly installed and that procedures were adequate.

The inspector reviewed the results of the vertical slice inspections j referenced above, performed on the EDG, High Pressure Safety Injection

! (HPSI), and CCW systems. The results were documented in CRs 96-1588 (Unit 1 items for Operations disposition), 96-1589 (Unit 1 items for Engineering disposition), 96-1360 (Unit 2 items for Operations i disposition) and 96-1361 (Unit 2 items for Engineering disposition). In ,

i general, the licensee's findings were consistent with NRC findings in j

! this area and included cases in which procedure-to-drawing deviations existed in valve position, cases of annunciator response summary errors existed, cases of instrument range differences between the UFSAR and I design documents, and cases of configuration differences between the plant and design documents.

The inspectors found that the licensee had initiated actions 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 i licensee's actions will be determined in followup inspections to the i apparent violations described above.

URI 96-04-05, " Configuration Control Management," is closed.

c. Conclusions The inspectors concluded the following with respect to configuration contrcls:

That programmatic flaws resulted in one apparent violation involving the issue of configuration management and the licensee's ability to correctly translate design changes into drawings and procedures. The apparent violation included five examples: j

1) One example of a failure to update an annunciator response. summary when a hydrazine tank low level alarm setpoint was changed via PC/M.

2) One example of a failure to update an engineering drawing to reflect the deletion, via PC/M, of valves and piping for the Intake Cooling Water System.

3) One example of a failure to update an annunciator response summary to reflect a change, made via PC/M, which removed automatic and control room operation capability from a pair of valves.

4) One example of a failure to update an annunciator response procedure to reflect a change, made via PC/M, which removed the alarm function from an annunciator.

1 13

5) One licensee-identified example of a failure to update an operating procedure to in .lude operational limitations imposed by a PC/M-transmitted spent vuel pool heat load calculation. . ,

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The licensee's QA organization was identifying specific areas of concern in the configuration management area. The licensee had initiated actions to address the configuration management deficiencies identified by both the NRC and the licensee's QA organization.

V. Manacement Meetinos and Other Areas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee  ;

management at the conclusion of the inspection on July 12. The licensee '

acknowledged the findings presented. l

- The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was l identified.

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- .- . . -_ -- -_ -- = . - - . - . . - _ - . --. - ..

1 14 PARTIAL LIST 0F PERSONS CONTACTED Licensee Bladow, W., Site Quality Manager Bohlke, W., Vice President, Engineering Burton, C., Site Services Manager Dawson, R., Business Manager Denver, D., Site Engineering Manager Fulford, P., Operations Support and Testing Supervisor Holt, J., Information Services Supervisor Johnson, H., Operations Manager Scarola, J., St. Lucie Plant General Manager Weinkam, E., Licensing Manager Other licensee employees contacted included operations, engineering, maintenance, and corporate personnel. j i

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15 INSPECTION PROCEDURES USED-IP 37551: Onsite Engineering

, IP 64704: Fire Protection Program j IP 71707: Plant Operations i IP 92901: Followup - Plant Operations 1 IP 92903: Followup - Engineering j ITEMS OPENED, CLOSED, AND DISCUSSED j Opened j 1

50-389/96-12-01 EEI Failure to Perform a 10 CFR 50.59 Safety Evaluation for CEDMCS Enclosure 1 50-335,389/96-12-02 EEI Failure to Perform a 10 CFR 50.50 Safety Evaluation For Use of a Temporary Fire Pump

, 50-335/96-12-03 EEI failure to Perform a 10 CFR 50.59 Safety I Evaluation For Change in Setpoints Listed in UFSAR i

50-389/96-12-04 EEI Unreviewed Safety Question Involving EDG 2B 50-335,389/96-12-05 EEI Failure to Ensure Configuration Control l

Closed

50-335,339/96-04-05 URI Configuration Control Management Discussed 50-335,389/96-04-09 URI Failure to Update UFSAR I

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LIST OF ACRONYMS USED ATTN Attention i CCW Component Cooling Water l CEDMCS Control Element Drive Mechanism Control System CFR Code of Federal Regulations CR Condition Report CW Circulatory Water DFOST Diesel Fuel Oil Storage Tank DPR Demonstration Power Reactor (A type of operating license)

DWG Drawing EA Enforcement Action EDG Emergency Diesel Generator EEI Escalated Enforcement Item FIS Flow Indicator / Switch F0 Fuel Oil FPL The Florida Power & Light Company FRG Facility Review Group ,

l gpm Gallon (s) Per Minute (flow rate) I HPSI High Pressure Safety Injection (system)  !

ICW Intake Cooling Water IR [NRC] Inspection Report JPN (Juno Beach) Nuclear Engineering LIS Level Indicating Switch MV Motorized Valve NLO Non-Licensed Operator No. Number NPF Nuclear Production Facility (a type of operating license)

NRC Nuclear Regulatory Commission NUREG Nuclear ReSulatory (NRC Headquarters Publication)

ONOP Off Normal Operating Procedure OP Operating Procedure PACB Plant Auxiliary Control Board PC/M Plant Change / Modification PDR NRC Public Document Room PM Preventive Maintenance PRA Probabilistic Risk Assessment PSL Plant St. Lucie QA Quality Assurance QI Quality Instruction QSL Quality Surveillance Letter '

SAR Safety Analysis Report SE Safety Evaluation SFP Spent Fuel Pool SIAS Safety Injection Actuation System SIT Safety Injection Tank St. Saint TQR Topical Quality Requirement UFSAR Updated Final Safety Analysis Report URI [NRC] Unresolved Item USNRC Unite States Nuclear Regulatory Commission USQ Unreviewed Safety Question

ENFORCEMENT ACTION WORKSHEET ,

INADEQUATE CONFIGURATION MANAGEMENT PREPARED BY: Mark S. Miller DATE: July 1, 1996 i NOTE: The Section Chief of the responsible Division is responsible for prr;paration of this EAW and its 4 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; appropnate Ril DRP, DRS; appropriate NRR, NMSSI. A Notice of

' Violation (without "boilerplate") which includes the recommended severrty 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 when the requirement was violated. F ty/

/

as to how and

.Sig)& ure

1. 'Mf"<N

! Facility: bT , ( "< 4 E Unit (s):

Docket Nos:

License Nos:

Inspection Report No:

Inspection Dates:

Lead Inspector:

, 1. Brief Summary of Inspection Findings: (Always include a short statement of the

< regulatory concerntviolation. Reference and attach draft NOV. Then, erther 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 deficiency, identified by the licensee is identified. The licensee-PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

.- - .- -. - . -. - - .. - ~ . . .. . _ - .

ENFORCIMENT ACTION woaxsamur 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.

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l PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE

ENFORCEMENT ACTION -3 -

WORKSEEET 2.- Analysis of Root Cause:

Lack of formality in the licensee's program for preparing and implementing Plant Change / Modifications (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, repetrtiveness, willfulness, etc.)

Aggregation of examples and application of' Supplement I, C.7, a j breakdown in the control of licensed activities involving a number of

violations that are relate'd 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 4 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 3

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.)

i EA 96-040 - Boron Overdilution Event, Supplement 1, 1/22/96 '

4 EA 95-180 - Inoperable PORVs due to Inadequate PMT, Supplement 1, 8/4/95 j

5. Identification Credit? No I 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 i corrective action began in late April, when we identified drawing errors i and additional annunciator response procedure errors.

Enter date Licensee was aware of issues requiring corrective action:

, [4/96]

6. Corrective Action Credit? Yes Brief summary of corrective actions:

1 In response to the issue, the licensee adopted corrective actions which included:

e implementing design control processes from Turkey Point, which 1

PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

4 ENFORCEMENT ACTION ,

WoRKSEEET  !

I provided more positive control over the initial reviews and l documentation of required actions for PC/Ms. l

- 1 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  !

9; 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, d

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. j

8. Is A Predecisional Enforcement Conference Necessary? No .

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9. Non-Routine Issues / Additional Information: )

9 PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

l ENFORCDGNT ACTION -5 -

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)

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11. Regulatory Message: l Positive control must be established and maintained over-the design change process, with particular emphasis on ensuring that design i features and constraints are properly incorporated into procedures and i drawings, l

12. Recommended Enforcement Action:

SL IV

13. This Case Meets the Criteria for a Delegated Case. [EICS - Enter Yes or Nol i

14. Should This Actiori Be Sent to OE For Full Review? [EICS - Enter Yes or Nol If yes why- '

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15. Regional Counsel Review [EICS to obtaini l No Legal Objection Dated:

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16. Exempt from Timeliness: [EICSI Basis for Exemption:

Enforcement Coordinator:

DATE:

J 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 wi11 fulness. 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. l i

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 har 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 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:

[] Applicable Tech Specs along with bases:

[] Applicable license conditions

[] Applicable' licensee procedures or extracts 1

[] 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 5D.59 or systems operability ,

1

[] Referenced ORDERS or Confirmation of Action Letters I

[] Current SALP r: port-summary and applicable report sections

[] Other miscellaneous documents (List):

PROPOSED ENFORCEMENT ACTION - NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

Inspection Report 96-04 identified several potential configuration i 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 ON0P 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.

• 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 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 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/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.

• 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 i

PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE WITHOUT THE APPROVAL OF THE DIRECTOR. OE I

the applicable proczdure. 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:

e Ensuring that initial SFP temperature was less than or equal to 106*F.

e Ensuring that the reactor was suberitical for at least 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> prior to commencing the offload, c Verifying that the SFP high temperature alarm, which annunciated in the control room, was operable.

e Verifying that two SFP cooling pumps were in operation.

o Verifying that CCW flow to the fuel pool heat exchangers was 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 pf 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 action directed) inaccuracies in the Annunciator Response Summaries had 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 l requirements and the design basis are correctly translated into I specifications, drawings, procedures, and instructions. The licensee's Topical Quality Assurance Report, TQR 3.0, revision ll, " 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

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procedural inadequacies brought on by the implementation of PC/Ms c the

, 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 review forms; however, this documentation amounted to a "yes" or "no" ,

1 determination, as opposed to specifying the procedures which required t revision. As a result, no formal process tracked the completion of i l~ 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-o 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, e 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 instructions (this applied to Safety Evaluations which included ,

conditions to ensure that the assumptions in the evaluations were i maintained valid).

The inspectors found the licensee's findings to be in general rgreement with observations made by the NRC. i In response to the issue, the licensee adopted corrective actions which ,

included:

1 e Implementing design control processes from Turkey Point, which provided more positive control over the initial reviews and 1 documentation of required actions for PC/Ms. '!

I 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 duririg 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- 1

, 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 .

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. violation described above.

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10 CFR 50 Appendix B " Quality Assurance Criteria for Nuclear Power 9

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 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." 1 4

Contrary to the above: l l

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1. On January 6,1995, the licensee failed to coordinate 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 setpoint of 35.5 inches in the procedure.

2. On 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 Piping Renovation]. The as-built Dwg. No. JPN-341-192-008 was not incorporated in Dwg. No. 8770-G-082, " Flow Diagram Circulating and i 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, 199'4, 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 & 48 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 ON0P 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 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 energized these annunciators bastd on switch '

position were removed to eliminate nuisance alarms.

5. On May 12, 1996, the licensee failed to coordinate a design change with an operational procedure change when Unit 1 fuel offload was commenced without incorporating 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 (minimum requirements for operating Spent Fuel Pool pumps and component cooling water flow were not met at the time fuel movement was initiated).

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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 en Enforcement Panel. The Section Cnief shall also be responsible for

, providing the meeting location and telephone bridge number to attendees via e-mail LENF.CRP, CFE, OEMAIL, JXL, JRG, SHL, LFD; appropriate Ril DRP, DRS; appropriate NRR, NMSS). A Notice of Violation (without "boilerplate") which includes the reconsner.ded severity level for the violation is required. Copies of applicable Technical Specift:ations 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 Facility: St. Lucie Unit (s): I and 2 Docket Nos: 50-335, 389  ;

License Nos: DPR-67, NPF-16 Inspection Report No: 96-12 Inspection Dates: ??

Lead Inspector: John York

1. Brief Summary of Inspection Findings: Laiways include a short statement of the regulatory concern / violation. Reference and attach draft NOV. Then, either sunenarite the inspection findings in thib 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 ga'hered 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 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.

Examole__l-An enclosure was fabricat.ed in a safet: elated 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 or.e 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.

E cole 4-The licensee changed the refueling hoist interrupt setpoints l PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE "VITHOUT THE APPROVAL OF THE CIRECTOR. OE

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. ENFORCEM2NT ACTION _ i i woRKSHEET with only 'an engineering analysis. Since the set points were outside j the UFSAR values a 50.59 safety analysis was required.  ;

See attached IR feeder and proposed NOV for details. l

2. Analysis of Root Cause:

Attention to detail, inadequate review of UFSAR in the 50.59 process. 1 i

3.- P sis for Severity Level-(Safety Significance): tinclude example from the l supplements, aggregation, repetitiveness, willfulness, etc.) l 1

i- The number ot 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 req ired 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 EAW, Supplement, and identification date.)

None identified? h

5. Identification Cre r ? Depends on the example.

! Item'l-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.  ;

1 (No) ,

I Item 4-Licensee STA and safety commmittee identified that a 50. 0 safety analysis had not been performed. (Yes) d Enter date Licensee was aware of issues requiring corrective action:

(5/96]

6. Corrective Action Credit?

Brief summary of corrective actions:

'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 being changed, and root-cause determinations were initiated.

Explain application of corrective action credit:

PROPOSED ENFORCEMENT ACTION . NOT FOR PUBLIC Dit 'LOSURE WITHOUT THE APPROVAL OF THE DIRECTOR, OE

_. .- . - -. -. . - - - - -. - -. -. .-. ~ - . -

ENFORCDG3fT ACTION . WORKSHEET-Corrective action appears to be of appropriate scope.

7. Candidate For Discretion? Yes Explain basis for discretion consideration: 4 Licensee's performance has been considered superior in the past.

8. Is A Predecisional Enforcement Conference Necessary? Yes  ;

Why:

To determine adequacy 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):

9. Non-Routine Issues / Additional Information:

This issue should be discussed during a PEC along with the issues panelled the week of July 1.

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.10. This Action is Consistent With the_Following Action (or Enforcement )

Guidance) Previously Issued: tEles to provide) (If inconsistent, includes)

Basis for Inconsistency With Previously Issued Actions (Guidance)

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11. Regulatory Message: l Control must be maintained over the screening and performance of safety 1 analyses (10 CFR 50.59).

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12. Recommended Enforcement Action:

SL III-Under cu. rent NUREG 1600 examples I.C.5.and I.C.~7 under draft examples I.C.10 and I.C.11.

13. This case Meets the Criteria for a Delegated Case. reics Enter Yes or No) i 1

14. Should This Action Be Sent to OE For Full Review? teics Enter Yes or No)

If yes why:

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15. Regional Counsel Review trics to obtain)

No Legal Objection Dated:

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16. Exempt from Timeliness: teics) -

Basis for Exemption:

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DATE:  !

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ENFORCEMENT ACTION WORKSHEET - ISSUES TO CONSIDER FOR DISCRETION l [] 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.

1 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.

[] Current violation is directly repetitive of an earlier violation. .

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! [] Excessive duration of a problem resulted in a substantial increase in

, risk.

[] Licensee made a conscious decision to be.in noncompliance in order to i

. obtain an economic benefit.  :

i a [] Cases involves the loss of a source. (Note whether the licensee self- 1 l

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.

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Enclosure 3 REFERENCE DOCUMENT CHECKLIST t

[] 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

[] Applicable licensee procedures or extracts

[] Copy of discrepant licensee documentation referred to in citations such- l as NCR, inspection record, or test results [

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[.] 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):

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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 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 the environment until the leak could be identified and corrected.

As a compensatory measure, the licensee proposed dedicating an NLO to the task of opening the closed valve in the event of an EDG f 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 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 valve and open it. The NLO performed this task in approximately seven minutes.

In considering the issue, the licensee employed PRA techniques to estimate the increase in the risk of the loss of the 283 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 in nector 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 mcdes 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 I

PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE l WiiHOUT THE APPROVAL OF THE DIRECTOR, OE 1 l

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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 the question to NRR for resolution.

After consideration of the issue, the NRC determined that 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 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, 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").

B. Safety Evaluation for CEDMCS Enclosure 1

On June 4, 1996, a control room annunciator indicated that an undervoltage condition existed on the Control Element Drive 1 Mechanism Control System (CEDMCS). Operations responded to the CEDMCS equipment and noted that the CEDMCS enclosure was approximately 11 degrees warmer than normal. This enclosure is located in the cable spreading room on the 43 foot elevation of 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 l following items with appropriate plant corrective action tracking l number were identified by these reports: )

CEDMCS enclosure and air conditioning units did not appear on the plant's controlled drawings. (STAR 951320) l 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 '

cabinets. 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 inste11ation 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 CO.59 review was apparently not performed when the enclosure was originally erected. The CEDMCS was described in the UFSAR but the cooling system and enclosure for the CEDMCS were not described in the UFSAR. This was identified as another example of URI 50-335, 389/96-04-09,  ;

" Failure to 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 i During the Spring 1996 Unit I refueling outage, one of the two l Unit 1 EDGs had been placed out of service to perform maintenance i and modification work activities. Only one EDG was in service to l provide power in the event of a loss of power event. To prevent a l possible overload on the single EDG unit, a number of breakers to various components were opened and the units 480V electrical 1 busses were crosstied in accordance with OP l-0910024, Rev 6, "Crosstying/ Removal of 480V Buses." One of the components removed from service was Fire Pump 1B. The breaker to this fire pump was  ;

opened on May 21, and this pump was removed from service and remained out of service on June 8, the end of this inspection ,

period. I 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.

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 protaction 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

an alternate backup pump had not been exceeded. This mat the requirements of AP 1800022 for one pump being inoperable.

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 enginer. ring 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, 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 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.

. 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 3

! values would affect the FSAR and thus the deviation report (CR) was written.

St. Lucie Quality Instruction (QI) 2.0, Engineering Evaluations, i Rev. I dated January 31, 1996 provides general requirements and ,

guidance for the development and processing of engineering i 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 proce', is designed to determine whether

the activity requires a comple.310 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 j 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 eval uation" . l 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

. - . . ~ - . .

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 '

l 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 of a malfunction of equipment important to safety previously evaluated in the safety aralysis report may be increased. (b)(1) stated, in part, 1

> the licensee shall maintain records of changes in the facility to the i 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 j involve an unreviewed safety question.

. The fallowing four examples of a violation of these requirement were identified.

Example 1-Contrary to the above, in July, 1995, the licensee made a change to the facility which involved an unreviewed safety question when 4 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 (operator failure to open a i 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

, , the Emergency Diesel Generator above that previously evaluated in the safety evaluation report.

k 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 d

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 I safety evaluation. The fire protection water supply system is shared by  !

Units 1 and 2 and is described in UFSAR Appendix 9.5A, Section 3.0.

i Example 4-Contrary to the above, the licensee used an engineering evaluation to change the set points and procedures described in the FSAR i for operating the fuel hoist without performing a 10 CFR 50.59 safety  !

analysis / evaluation.

1 PROPOSED ENFORCEMENT ACTION NOT FOR PUBLIC DISCLOSURE l WITHOUT THE APPROVAL OF THE DIRECTOR. OE l

August 6, 1996 HEMORANDUM T0: Jon R. Johnson, Acting Director Division of Reactor Projects Region II l FROM: Frederick J. Hebdon, Director /s/ '

Project Directorate 11-3 Division of Reactor Projects I/II Office of Nuclear Reactor Regulation

SUBJECT:

TECHNICAL ASSISTANCE REQUEST (TIA 95-013) IN ADDRESSING ISSUES RELATING TO THE ADEQUACY OF A 50.59 EVALUATION AT ST. LUCIE UNIT 2 (TAC N0. M93372)

In a memorandum dated August 28, 1995, NRR assistance was requested in l evaluating the acceptability of a 50.59 evaluation supporting isolation of a diesel generator fuel oil transfer system leak at St. Lucie Unit 2. In l addition, several generic questions concerning the relationship between l Probabilistic Risk Assessment (PRA) evaluations and 10 CFR 50.59 requirements were presented for NRR response.

The Probabilistic Safety Assessment Branch, NRR, has completed its review of l these issues. A discussion of these issues and NRR's response to your l questions is contained in the attached memorandum dated July 30, 1996. The I positions stated in the attachment have been reviewed by the Office of the General Counsel and they have no legal objection to these positions.

Docket No.: 50-389

Attachment:

As Stated ,

cc w/ attachment: R. Cooper, RI $ l W. Axelson, RIII  ;=  ;

J. Dyer, RIV E l

Contact:

L. Wiens, NRR\PDII-3 415-1495 3

Distribution @

Docket File St. Lucie Rdg. SVarga JRoe JZwolinski JFlack, SPSB AChaffee Klandis, RII DOCUMENT NAME: G:\STLUCIE\TIA13.RES To receive a copy of this document, indicate in the box: "C" - Copy without attachment / enclosure "E" - Copy with attachment / enclosure "N" - No copy 0FFICE PO!!-3/LA  % lQ PO!! 3/PM , f lFl POII-3/0 ..1 iOl l CAME 8Clayton nF LWiens /We f FMcocon 7

'E 08/sp/96 08/6/96 08/ / /96 Of flCI AL RECGRO COPY J

, kO 't D2S O -

. _ _ . _ _ _ . _ _ ~ _ _ . _ _ . . _ . . _ . _ . ~ . . . _ . . _ . _ . . _ _ . _ _ _ . _ . . _ . . _ . . . . _ _ _ _ _ _ _ . . . . _ _ _ . - _ . _ _ __ .

' duly JU. I170 '

l MEMORANDUM TO:. Frederick' Hebdon, Director

Project Directorate 11-3

[

Division of Reactor Projects I/II i.

FROM: Edward J. Butcher, Chief Probabilistic Safety Assessment Branch l

Division of Systems Safety and Analysis

SUBJECT:

RESPONSE TO REQUEST FOR ASSISTANCE IN ADORESSING ISSUES REGARDING ST. LUCIE EMERGENCY DIESEL GENERATOR FUEL OIL i TRANSFER SYSTEM LEAK ISOLATION AND USING OPERATOR ACTION IN l- PLACE OF AUTOMATIC ACTION (TIA 95-013)

! Plant Name: St. Lucie Unit 2 i Utility: Florida Power & Light Co.

Docket No.: 50-389 l TAC No.: M93372

j. Project Manager: Leonard A. Wiens

Review Branch: SPS8 l Review Status: Coeplete i

The attachment to this memorandum is our response to TIA 95-013. It contains our responses to the specific questions raised by Region II regarding )

the 10 CFR 50.59 FPL Safety Evaluation (JPN-PSL-SENS-95-013), and the j application of PRA methodology and related issues. If you have any questions i

regarding our response to the TIA request or regarding the licensee's PRA l .

i assessment which was included in the TIA, please contact John Schiffgens at 415-1074 (E-mail: JOS), or John Flack at 415-1094 (E-mail JHF). In addition, we are in the process of developing a formal position on the use of PRA in the 10 CFR 50.59 process which will be sent to you in a separate memorandum.

Attachment:

As stated DISTRIBUTION Docket File SPSB File LWiens

• SEE PREVIOUS CONCURRENCES. .

DOCUMENT NAME: G:

t. . .em.4 \.STLUCIEQ.

.ms = m. IIA e . c . .n -....  :.c. .n. cam.w.=i..=. r-* ,

OFFICE SPSB:DSSA lE SPSB:DSSA lE SPSB:DSSA E SPSB:DSSA lE DDSSA [E NAME SRosenberg*- JSchiffgens* JF1ack* EButcher* GHolahan*

DATE 5/29/96 5/29/96 5/29/96 5/31/96 6/11/96

( WI /

OFFICE PECly0 RPM lE OGC /v4/Vl, E / I NAME DMatthews M4e AANW_ /

~'TE (//0K/96- 1/f $96 //// / /96 / /96 0FFI AL RECORD COPY ATTACHMENT gg I 07 'i

arxw mu. eowo em m ,:;

=

l there is ne increase in the probability of ooourranse of an assident

previously analysed in the saa.

' 2) Door the proposed activity lacrease the consequenans of an aasident previously evaluated la the SART The ocasequences ef an aseident previously evaluated in the S&R have

! not been increased since the parformance and -operation of the SS ane j will not be impoeted by this change. Additionally, this okange will not arente a new path for uncontrolled radieastive releases and v111 mot adversely affect any radiation monitorias equipment or equipasat which is relied upon to mitigate radiological consequences of aa aooident.

I '

+

3) Does the proposed activity lacrease the probability of oscurrence l of a malfunction of equipment Laportant to safety pawriously j evaluated La the SARP 1

l The proposed activity slightly alters the method for initiating fuel

j flew from the Dosts to the EDs Day Tanks. Valve v17218 is normally

p 4 LOoEED OPEN valve that does not require any actuation is order to..

j t- ensure a flew path from the Dosts to the Sa 300 day tanks. This

.- evaluation alless V17 tis to be placed in the CLOSED position peerided j d the identified compensatory actions are implemented. These Cl compensatery actions assure the reliability of the EDS faei eil supply. additionally, once V1721s is opened, the fuel oil transfer 2l

~

system fumatione me originally designed. -

i As identified in section 5 of this evaluation, the failare of Y17216 I

to opea (due to either valve or operator failure) is possihte. suet

.= a failure would result in the less of the 23 EDS due to fuel  !

i' starvation after appreminately two hours of operation. A risk i assessmaat was condueted by Fpt's Pan group to determine the change 3; in the reliability of the 3 side electrical power system fellowing implemmataties of the specified compensatory actions. siaea the EDS d syntaa is only required to perform its safety functies following a 7 lose of offsite power to the safety electriemi huses, failures of the l Q system were taken in essjuaotion with a loss of offsite power.

v L In the proposed configuration, the shange in frequeasy of a less of gi the 3 side electrical power is slightly increasedi hosever, this small ineresse'in met eensidered significaat when eenpled with the i fast that plaat pseeedares will be nodified to provide for operators d who v11Ehe spesially instructed to open vi7 sis as seen as possible .

Z and witMa 20 aiantes after an unplanned start of the 23 3DS. Based I on the'above, it osa be,ocaeluded that the probability of eesarreams of a malfunction of equipment important to satsty previously .

evaluated in the safety analysis report has not been ineressed. l

4) Does the proposed activity increase the consegusmons of a as2ftenation of equipseat laportant to safety prerhafy arminated LD the BART i l

The eensequemose of a malfuastion 'of equipment important to safety  !

previously evaluated in the s&R have not been increased since the I most limiting failure would result in the loss of a single EDS which is an analysed event. We other safety systems or equipment required 1

50'c 29 19 cm - astfr0 tuacitaw at ml 4 WW P:0T E I T5 c0

i 1 i O j p g sea m ro

• EN N

mesr.me==s. n. .

i Pass 4ef18 i i operoitity of th. 3eet ,ipe has been address.4 in he ,ef.es.e .

i STER. The suspeeted underground leak has been quantified at l i

appreminately 15 gal / day. The 23 DOTP has a design fley rate of SS GPM (reference 1) and provides sufficient flow marcia to deliver fuel l

to tanks.

the 23 EDe to maintain the required fuel oil level in the day )

j  !

l 1 rist assessment was conducted by FFL's Ps1 group. This assessmLfc,4 '

i i

used the baseline Unit 2 Ps1 model to estimate the change in fr of loss of the 233 4.15kT bus with a less of grid ialtiating event i

f the addition of two new 23 EDS failure modes (i.e., failure of the EBd j

i p fuel oil amanal isolation valve to open and failure of the operator to open the olosed isolation valve) . A non-removery prahabitity et

! dT 3.01E=3 imelation valve.

uns used for the operator failing to opea the feel oil

{ ~2 This probability was based on the en-easteel model f

of 02c1 using a120 minute available time and a 20 minute mesa response time.

i 'I l

..../ Two cases were assessed l [; Case 1: Baseline Ps1 model case h! case 2: Baseline model with the additional failure modes for the 23 l  !

BDG (manual fuel oil isolation valve failing te spea .and

. eparator failing to open the valve).

! The estimated frequency for each ease is as follows:

Case is 1.73E-3/yr l case 2: 1.e4E-3/yr

{ t 4 This fadicates that the additional failure modes resulting from the closed fuel oil isolation valve results la an approximate 6% skaage in the estimated frequeasy per year of loss of the Unit 2 233 4.askT bus.

atnataar Based on the above sessario, sufficisat time esists for an operator to apen valve vi7216 prien to DOTP 23 automatically starting te replenish EDS 23 day tanks to aersal levels and sufficient margia esists from the 23 DOTP to deliver the required flow rate of fuel to the 23 EDS, ocasidering the esposted ground leakage less. Zaplementaties of the actione requ, ired in section 9.4 will provide fumational onpabilities equivalent to the original seafiguration.

20 d Z??? !?? 0? ~ 'HG"'"*d* 4 #

1 I

i CLOSING REMARKS i (L. Reyes) l i

in closing this predecisional enforcement conference, I remind the Licensee of two things:

I i

First, the apparent violations discussed at this predecisional enforcement conference are subject to further review and may be subject to change prior to any resulting enforcement action.

I Second, the statements of views or expressions of opinion made by NRC employees at this predecisional enforcement conference, or the j lack thereof, are not intended to represent final agency determinations ,

or beliefs.

PROPOSED ENFORCEMENT ACTION NoT FoR PUBLIC DISCLOSURE WITHoUT THE APPROVAL OF THE DIRECTOR, oE

! UNITED STATES l

NUCLEAR REGULATORY l COMMISSION i

L i

f# ""**4

• • +13

! ST. LUCIE ENFORCEMENT CONFERENCE NOVEMBER 14,1995 0

_ - - . - =_ _ . . - . - - - . . - .

NRC CLOSED PREDECISIONAL ENFORCEMENT CONFERENCE

. ST. LUCIE NUCLEAR PLANTS 4

NOVEMBER .14,1995 TAB TITLE 1 Predecisional Enforcement Conference Agenda 2 Expected Attendees, Meeting Announcement 1 3- Opening Remarks and Introductions i

4 NRC Enforcement Policy 5 Summary of the issues

?

.g 6 Statement of Concerns / Apparent Violations

7 Inspection Report No. 50-335/398/95-20 8 Enforcement Pre-Panel Questionnaire ,

l 9 50.72 Report, LER 95-006 10 FPL Engineering Evaluation 11 St. Lucie Action Reports 12 Closing Remarks:

PREDECISIONAL ENFORCEMENT CONFERENCE AGENDA '

l ST. LUCIE NOVEMBER 14,1995, AT 1:00 P.M.

NRC REGION ll OFFICE, ATLANTA, GEORGIA

1. OPENING REMARKS AND INTRODUCTIONS S. Ebneter, Regional Administrator i

11. NRC ENFORCEMENT POLICY B. Uryc, Director Enforcement and Investigation Coordination Staff 4

Ill.

SUMMARY

OF THE ISSUES S. Ebneter,' Regional Administrator IV. STATEMENT OF CONCERNS / APPARENT VIOLATIONS E. Merschoff, Director Division of Reactor Projects 1

V. LICENSEE PRESENTATION W. Goldberg, President, Nuclear Division l Florida Power and Light VI. BREAK / NRC CAUCUS Vll. NRC FOLLOWUP QUESTIONS Vill. - CLOSING REMARKS S. Ebneter, Regional Administrator k

EXPECTED ATTENDEES Licensee J. Goldberg, President, Nuclear Division D. Sager, Vice President, St. Lucie Site W. Bohlke, Vice President, Engineering D. Denver, Site Engineering Manager 1 B. Dawson, Licensing Manager C. Wood, Operations Supervisor

]

i l

MBL l l

Stew Ebneter, Regional Administrator, Region ll (Rll) '

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 l (EICS), Ril  !

Charles Casto, Chief, Engineering Branch, DRS, Ril Kerry Landis, Chief, Reactor Projects Branch 3, DRP, Ril Linda Watson, Senior Enforcement Specialist, EICS, Ril Carolyn Evans, Regional Counsel, Ril Richard Prevatte, Senior Resident inspector, St. Lucie, DRP, Ril j Edwin Lea, Project Engineer, Reactor Projects Branch 3, DRP, Ril l Larry Mellen, Project Engineer, Reactor Projects Branch 3, DRP, Rll l

J e j l

l

October 24., 1995 i

I i

, EA 95-222 Florida Power and Light Company ATTN: Mr. J. H. Goldberg I President - Nuclear Division P. O. Box 11000

Juno Beach, FL 33408-0420

SUBJECT:

CLOSED MEETING ANNOUNCEMENT - PREDECISIONAL ENFORCEMENT CONFERENCE ST. LUCIE - DOCKET NO. 50-335, 389 Gentlemen:

This letter confirms the conversation between Mr. B. Dawson of your staff and Mr. E. Lea, of the NRC on October 18, 1995, concerning a predecisional enforcement conference requested by us which has been scheduled for

November 14, 1995, from 1:00 p.m. to 3:00 p.m. The p'Jrpose of this conference is to discuss apparent violations regarding an August 10, 1995, event 4

involving the lifting of a thermal relief valve and its failure to reseat.

The location of the conference will be at the NRC Region II office, 101 Marietta Street, N.W., Suite 2900, Atlanta, Georgia. This meeting is a closed meeting'as per " Staff Meetings Open to the Public; Final Policy Statement" (September 20, 1994; 59 FR 48340).

Should you have any questions concerning this meeting, please contact Edwin Lea at 404/331-3641. <

Sincerely, Orig signed by Kerry O. Landis Kerry D. Landis, Chief ,

Reactor Projects Branch 3  !

Oivision of Reactor Projects l Docket No. 50-335, 389 License No. DPR-67, NPF-16

- 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 l Juno Beach, FL 33408-0420 cc: Continued see page 2 0FFICIAL COPY

s&L 2 cc: Continued:

J. Scarola. 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

J. R. Newman, Esq.

Morgan, Lewis & Bockius i 1800 M Street, NW L Washington, D. C. 20036 I John T. Butler, Esq.

. Steel. Hector and Davis

4000 Southeast Financial Center Miami, FL 33131-2398 i 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 Joe Myers, Director Division of Emergency Preparedness Department of Community Affairs 2740 Centerview Drive Tallahassee, FL 32399-2100 Thomas R. L. Kindred, County Administrator St. Lucie County 2300 Virginia Avenue Ft. Pierce, FL 34982 Charles B. Brinkman Washington Nuclear Operations ABB Combustion Engineering, Inc.

12300 Twinbrook Parkway, Suite 3300 Rockville, MD 20852 9

. - . - - - .-. . . . - . . . . . - . - - .. --~ _. - - . . . . . . . - - . - . . -.

i a

i  !

FPSL 3

! Distribution:

i j j

• Hard_ Paper Copy  !

F. Gillespie, DISP /PIPB 1

RII Regional Coordinator OEDO (17G21) l l J. Norris,'NRR i G. Hallstrom, RII f Region II Receptionist

! PUBLIC '

i j NRC Resident Inspector

U.S. Nuclear Regulatory Comm.

i 7585 South Highway AIA i Jensen Beach, FL 34957-2010 l' e E-Mail Meeting Announcement Coordinator, 0ADM/DFIPS (PMNS)

Region II Administrator's Secretary j Region II Division Directors, and Deputies

Region II Public Affairs Officer

Region II DRP Secretary i

I

! l b l l

l

?

esaari To ptmlw= cocemasuf noogt yn #10 oproce SENATLAW j ,[ -

name etae DATT 10 /M/ 96 10 / 195 10 / 196 10 / 1 96 10 / / 95 10 / 1 96 ,

com (ves) no ves no ves no ves no ves no ves no  !

0FFICIAL RECORD COPY 00CLMENT IWIE: P:\sLEFB5.020 j

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_- ~ ...a... \

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, -7 l

I

^

j OPENING REMARKS AND INTRODUCTIONS (S. Ebneter) l i

I 1

3 Good morning. I am Stew Ebneter, Regional Administrator for the )

+

l Nuclear Regulatory Commission's Region 11 Office. This morning we will conduct a predecisional enforcement conference between the NRC l j- Land St. Lucie which is CLOSED to public observation.

e ,

1 1

l l

f The agenda for the' conference is shown in the viewgraph. Following 1

my brief opening remarks, Mr.- Bruno Uryc, the Director of the Region ll l 1

l -Enforcement Staff, will discuss the Agency's Enforcement Policy. I i will th'en provide introductory remarks concerning my perspective on j- the events to be addressed today. Mr. Ellis Merschoff, Director of the Division of Reactor Projects, will then discuss the apparent violations.

t You v0ill then be given an opportunity to respond to the apparent i 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. '

~ ,. _ _ _ -_ . ___. . . __ __ __

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 ha:ve follow-up questions. Lastly. I will provide concluding remarks. '

At thia point, I would like to have the NRC staff introduca themselves and then ask you to introduce ycur participants.

l

[lNTROD JCTIONS]

Thank you.

l I

Mr. Uryc will now discuss the Agency's Enforcement Policy.

1

1" I

l l

l NRC ENFORCEMENT POLICY (B. Uryc)

NRC Enforcement Pcli_cv 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.

l l

t The assessment of an apparent violation involves 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 Level I,11, 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, ard 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 of the inspection or investigation process before the staff makes its i

l final enforcement decision.

I l

The purpose of this conference is not to negotiate a sanction. Our purpose here today is to obtain information that will assist as in determining the appropriate enforcement action, such as: (1) a common understanding of the facts, root causes and rnissed 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 i I enforcement action. It is important to note that the decision to i

l conduct this conference does not mean that NRC has determined that l

a violation has occurred or that enforcement action will be taken. )

1

l l

l 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  !

i

/ack thereof, P.re not intended to represent final determinations or beliefs. .

l l

Following the conference, the Regional Administrator in conjunction l l

with the NRC Office of Enforcement and other NRC Headquarters l

offices will reach an enforcement decision. This process should take  !

about four weeks to accomplish. l l

Predecisional enforcement ennferences are'normally closed to the public as is this conf erence. However, the Commission implemented a  ;

trial program in July 1992 to allow certain enforcement conferences to i

be open for public observation. [ July 10,1992 - Federal Rep / ster]

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 will issue a press release 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the'  :

enforcement action is issued.

1

I y

i ,

SUMMARY

OF THE ISSUE l l (S. Ebneter) i I  !

l l

l l l

issue: ' Relief Valves Failure to Reseat After Lifting l

o l

! This is a Predecisional Enforcement Conference to discuss one l

l apparent violation associated with lifting of relief valves, the failure of the relief valves to reseat as designed, and the lack of prompt f corrective actions taken to prevent reoccurrence.

l l -

Corrective action requests were initiated in response to anomalous-l relief valve behavior identified on three separate occasions. We are .

l l concerned that once you were aware of the problems with the failure  ;

l of the relief valves to reseat as designed, corrective actions were not i

promptly initiated to prevent reoccurrence. In fact, because you failed to provide prompt corrective actions on the three separate occasions '

L that involved the failure of the relief valve to reseat, another event

, occurred on' August 10,1995, in which a relief valve lifted and failed to ' reseat. During the August 10,1995, event approximately 4000 gallons of reactor coolant inventory accumulating in the Unit 1 pipe i

,-r ir 5

- m -- - - - - - - 4 mr ,

tunnel, which resulted in a reduction in SDC inventory. A contributing cause to the event was an inadequate design margin between the relief valve reseat setpoint and SDC system operating pressure.

-- Additionally, the generic implications of safety related relief valves failing to reseat as designed potentially affected a number of valves in your plant. Therefore, we are particularly concerned thst these deficiencies were not promptly evaluated for the effect on operability of the other valves commensurate with the safety significance of this issue.

STATEMENT OF CONCERNS / APPARENT VIOLATION (E. Merschoff) 4 issue: Relief Valves Failure to Reseat After Lifting L

1 Thermal relief valve V3439 lifted and failed to reseat while placing

Shutdown Cooling (SDC) in service. On August 10,1995, at 0018, l

the 1 A Low Pressure Safety injection (LPSI) pump was started to initiate flow for SDC operation. During the pump start thermal relief valve V3439 lifted and did not reseat. SDC operation continued until 0215, on August 10, following a fire-watch call to the control room, which reported that water was issuing from a watertight door isolating the pipe tunnel from the Reactor Auxiliary Building. SDC was secured (both LPSI pumps were stopped). A contributing cause to the event was an inadequate design margin between the relief valve reseat setpoint and SDC system operating pressure. Documentation also indicated that St. Lucie Action Requests were initiated for anomalous relief valve behavior identified on February 20, March 2, and March.10, 1995. Additionally, the potential generic implications of safety related relief valves failing to reseat as designed was not evaluated for the

v Y

effect on operability in a timely manner commensurate with the safety

- significance of this issue.

i

\

j Defect: I i J l

The failure to take prompt corrective action for anomalous relief valve l I

behavior, that was identified in St. Lucie Action Requests initiated on t

February 20, March 2, and Maren 10,1995, led to the event on ,

August 10,1995. Unit 1 relief valve V-3439 lifted and failed to reseat r without operator intervention. This event resulted in approximately i 4000 gallons of reactor coolant accumulating in the Unit 1 pipe tunnel t l

and a reduction in SDC inventory.

\

Consequences:

i Relief valves that fail to operate within the established design limits

have the potential to reduce the effectiveness of those barriers that were designed to limit radioactive release, and provide cooling during emergency situations.

l l

1 1

1 I

Our findings are documented in NRC Inspection Report 50-335, 389/95-20, which were transmitted to you on October 26,1995. At this conference, we are affording you the opportunity to provide information relative to:

--- Any errors the inspection reports

--- The severity of the violations

--- Any escalation or mitigation considerations

--- Any other application of the Enforcement Policy relevant to this issue.

r ISSUE TO BE DISCUSSED ,

10 CFR 50, Appendix B, Criterion XVI, " Corrective Actions,"

requires, in part, that measures be established to assure that conditions adverse to quality are promptly identified and  !

corrected, j 1

The failure to take prompt corrective action for the conditions adverse to quality identified on February 20, March 2, and March '

10,1995, led to a repeat of the anomalous behavior on August 10,1995, when Unit 1 relief valve V-3439 lifted and failed to reseat without operator intervention. The subject event resulted in approximately 4000 gallons of reactor coolant accumulating in the Unit 1 pipe tunnel.

NOTE: The apparent violations discussed in this predecisional enforcement conference are subject to further review and are :bject to change prior to any resulting enforcement decision.

y October 25, 1995 EA 95-222 . 'I Florida Power and Light Company ATTN: Mr. J. H. Goldberg President - Nuclear Division P. O. Box 14000 Juno. Beach, FL 33408-0420

SUBJECT:

NRC INSPECTION REPORT NOS. 50-335/95-20 AND 50-389/95-20 Gentlemen:

This refers to the inspection conducted on August 10 through October 10, 1995, at the St. Lucie facility. The purpose of the inspection was to determine whether activities authorized by the license were conducted safely and in .

i accordance with NRC requirements. 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 inspectics are identified in the report. The inspector reviewed the event that occurred when the 1A LPSI pump suction relief valve V-3483 lifted and failed to reseat. The inspector also reviewed

.other documented events in which relief valves had lifted and failed to-reseat. Areas inspected included the licensee's immediate action taken once ,

the valve's failure to reseat was recognized, root cause determination, and 1 corrective act. ion taken by the licensee. Within these areas, the inspection consisted of selective examinations of procedures and representative records,  !

interviews with personnel, and observation of activities in progress. '

Based on the results of this inspection, apparent violations were identified ~

and are being considered for escalated enforcement action in accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy), (60 FR 34381; June 30,1995). The apparent violations identified are related to the failure to take prompt corrective action on an identified problem with safety-related relief valves lifting and not reseating. Accordingly, no Notice of Violation is presently being issued for these inspection findings. In addition, please be advised that the number and characterization of apparent violations described in the enclosed inspection report may change as a result of further NRC review.

A predecisional enforcement conference to discuss these apparent violations has been scheduled for November 14, 1995, at 1:00 p.m. The decision to hold a  :

predecisional enforcement conference does not mean that the NRC has determined that' violations have occurred or that enforcement action will be taken. This conference is being held to obtain information to enable the NRC to make an enforcement decision, such as a connon understanding of the facts, root corrective actions, significance of the issues and the need for lasting and effective corrective action. In particular, we expect you to address the safety significance of the thermal relief valves in this and other safety-related systems. In addition, this is an opportunity for you to point out any 0FFICIAL COPY QQ \ QNlG

i

$ FP&L 2

)- errors in our inspection report and for you to provide any information concerning your perspectives on 1) the severity of the apparent violations, 2)

! the application of the factors that the NRC considers when it determines the i amount of a civil penalty that may be assessed in accordance with Section

- VI.B.2 of the Enforcement Policy, and 3) any other application of the Enforce-i ment Policy to this case, including the exercise of discretion in accordance i with Section VII.

You will be advised by separate correspondence of the' results of our deliberations on this matter. No rescense regarding the apparent violation is i required at'this time.

',( 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.

j Should you have any questions concerning this letter, please contact us.

j Sincerely, j Orig signed by Ellis W. Merschoff

!- Ellis W. Merschoff, Director s

Division of Reactor Projects l Docket Nos. 50-335, 50-389-License Nos. DPR-67, NPF-16 i -

Enclosures:

l 1. NRC Inspection Report i

4 cc w/encls: )

1 D. A. Sager j l- Vice President -

{ St. Lucie Nuclear Plant  ;

P.-0. Box 128  !

Ft. Pierce, FL 34954-0128 1 I i H. N. Paduano, Manager j Licensing and Special Programs  !

J Florida Power and Light Company  ;

2 P. O. Box 14000

~ Juno Beach, FL 33408-0420 j J. Scarola .

!' Plant General Manager i St. Lucie Nuclear Plant P. O. Box 128 l i

Ft.~ Pierce, FL 34954-0128 i'

)

j cc w/ encl: See page 3

}

i l'

l 1

iI FP&L- 3 cc w/ encl:" Continued'

'l Robert E. Dawson Plant Licensing Manager O B Ft. Pierce, FL 34954-0218 i

\

J. R. Newman, Esq. j Morga'n, Lewis & Bockius i 1800 M Street, NW i Washington, D. C. 20036  ;

John T. Butler, Esq. I LSteel, Hector and Davis <

4000 Southeast Financial Center Miami, FL 33131-2398 '

Bill Passetti Office of Radiation Control

~ Department of Health and 3 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 a

Joe Myers, Director  ;

Division of. Emergency Prept. redness '

Department of Community. Affairs 3 2740 Centerview Drive- 1

-Tallahassee, FL 32399-2100 l Thomas R. L. Kindred 1 County Administrator I St. Lucie County 2300 Virginia Avenue Ft. Pierce, FL 34982 Charles B. Brinkman Washington Nuclear Operations ABB Combustion Engineering, Inc.

12300 Twinbrook Parkway, Suite 3300 Rockville,'MD 20852 i

l i

FP&L 4 Distribution w/encls:

J. Norris, NRR G. Hallstrom, RII PUBLIC NRC Resident Inspector U.S. Nuclear Regulatory Com.

7585 South Highway A1A Jensen Beach, FL 34957-2010 arur, Yo punne occousur noout I ) no OFFICE (\

SIGNATURE J[ ,

g jf gj pp g g Nauf Et.. xt. ise. ner ite uussier sSensun OATE io iJ5 es inster es to IEo es to ifri es so 125/ es so i i es COPY 7 M NO [S NO YES NO YES NO YES NO YES NO OFFICIAL RECORD COPY W UMENI NAME: P:\$L9520-

ge mIfrog UNITEo STATES d 4 NUCLEAR REGULATORY COMMISSION 3" 1 REGloN 11 1 E S 101 MARIETTA STREET, N.W., SUITE 2000 i G j ATLANTA, GEORGIA 303234190

• ..+

f Report Nos.: 50-335/95-20 and 50-389/95-20 i

Licensee: Florida Power & Light to 1 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 Inspection Conducted: August 10 through October 10, 1995 2

Lead Inspector: Mh) /1 8 /4 95 R.Prevatte,feniorgesident Date Signed Inspector ,

i i

M. Miller Resident Inspector 1 S. S n Headquarters Operations Officer, AEOD Approved by:

"K. taYdis, Chief

_ /0/Ef

[ rate Signed f

, b actor Projects Branch 3 i

Division of Reactor Projects l

SUMMARY

l Scope: This special resident inspection was conducted onsite as a result of l of an event that occurred in which the 1A LPSI pump suction relief valve V-3483 lifted and failed to reseat. Areas inspected included .

the licensee's immediate action taken once the valve's failure to reseat was recognized, root cause detennination, and short term corrective action taken by the licensee on this and other potentially affected valves.

Summary: The licensee's corrective actions for the valves potentially affected by the subject event were comprehensive and sound.

However, actions could have reasonably been expected to be performed in a much more timely fashion based on similar events that had '

occurred months earlier. The licensee's failure to assure engineering involvement in addressing the setpoint issue earlier in the process contributed to the delay.

16I!l'!C Y ((

p  !

REPORT DETAILS i 1. -Persons Contacted  !

Licensee Employees

• R. Ball, Mechanical Maintenance Supervisor i

!

• W. Bladow, Site Quality Manager

• L. Bossinger, Electrical Maintenance Supervisor ,

H. Buchanan, Health Physics Supervisor l C. Burton, Site Services Manager 4

• R. Dawson, Licensing Manager  !

• D. Denver, Site Engineering Manager  ;

J. Dyer, Maintenance Quality Control. Supervisor i

! H. Fagley, Construction Services Manager

P. Fincher, Training Manager j' R. Frechette, Chemistry Supervisor P. Fulford, Operations Support and Testing Supervisor K. Heffelfinger, Protection Services Supervisor

• J._Marchese, Maintenance Manager

• R. Olson, Instrument and Cor. trol Maintenance Supervisor W. Parks, Reactor Engineering Supervisor

• C. Pell, Outage Manager L. Rogers, System and Component Engineering Manager

• D. Sager, St. Lucie Plant Vice President

• J. Scarola, St. Lucie' Plant General Manager

• J. West, Operations Manager

• C. Wood, Operations Supervisor W. White, Security Supervisor Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.  ;

i NRC Personnel M. Miller, Resident Inspector R. Prevatte, Senior Resident Inspector

• S. Sandin, Headquarters Operations Officer, AEOD

• Attended exit interview  !

Acronyms and initialisms used throughout this report are listed in the  :

last paragraph. -

2. Shutdown Cooling Relief Valve Lift A. Background Infomation 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

2 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 as the LPSI pump was started. As corrective action, the licensee revised OP 1-0410022,

" Shutdown Cooling," to change the methodology of starting the LPSI pump to the following:

e Shut LFSI pump discharge isolation and LPSI header isolation valves e Start the LPSI pump e Immediately open the LPSI pump isolation valve e Throttle open two LPSI header isolations to 150 gpm per header e Run for 15 minutes e Start the second pump e Throttle open the remaining LPSI header isolation valves to 150 gpm per header e Wait 5 minutes e Incrementally open header isolation valves to obtain full fl ow.

The licensee reasoned that this 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 service to support a cooldown required due to inoperable PORVs (see IR 335/95-16), V-3439, the A LPSI header thermal relief, lifted resulting in a loss of approximately 3500-4000 gallons of RCS coolant in the Unit 1 Pipe tunnel. The following timeline was developed from operator interviews, logs and instrumentation data:

0018 A LPSI pump start (ANPS, WE, Logs)

Pressurizer level begins to drop (strip chart data) 0025 ANPS directs SNPO to tour pipe tunnel due to minor reduction in pressurizer level (ANPS)

No increases in HUT, RWT, etc noted (ANPS)

SNPO reports no unusual conditions in pipe tunnel 0105 B LPSI pump start (ANPS, WE, Log)

Pressurizer level recovers and oscillates (strip chart) 0140 Cooldown flow established (ANPS, WE) 0210 Fire watch calls control room, reports water issuing from watertight door isolating pipe tunnel from RAB (ANPS, WE) 0215 SDC. secured (ANPS, WE)

Pressurizer level increases and stabilizes (strip chart) 0226 Floor drain isolation valves (FCV 25-1 through 7) noted to be closed on control panel (ANPS, WE)

, Drain valves subsequently opened (ANPS, WE)

Flooding in RAB ONOP entered (ANPS)

b n

l 3  :

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) i Operators cycle various isolation valves looking for leak l 0611 1A LPSI pump started with NWE observing in pipe tunnel  ;

(ANPS) 0612 NWE identifies V-3439 as passing water (ANPS) -

! The licensee concluded that the cause of the. relief valve lift was i a pressure surge while LPSI pumps were operating in a low-flow condition. The combination of RCS pressure (a maximum of 267 psia at the time) and LPSI pump discharge head at essentially no flow j

(approximately 182 psid), combined with possible pressure

perturbations (when starting the pump), was considered enough to 2

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 I L isolation valves, j i

3 V-3439 was designed to provide a 10 percent blowdown, which, if applied to the lower acceptable lift setpoint 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 reseat (assuming i only a 10 percent blowdown). The volume of the RCS and pressurizer would preclude sJCh a restat 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 i some areas), the inspector estimated that approximately 3500

( gallons were lost. The CVCS makeup integrator, measuring volume i added to the VCT in maintaining pressurizer level on setpoint, I

i. indicated that 4000 gallons were added to the VCT. i

{ C. Licensee Evaluation of Effectis Of Event on Plant Operation ,

1

' 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 o were left closed for troubleshooting and were never reopened.

This item is further discussed in IR 95-15.

j The licensee prepared an evaluation of the effects of the subject setpoint/ blowdown values on plant operation. JPN-PSL-SENP-95-101, i Rev 1, " Assessment of the Effects on Plant Operation of Lifting j- the LPSI Pump Discharge Header Thermal Relief Valve," concluded 3

4 that the subject condition would not have a significant effect on a

I e

e .

, 4 safe plant operation'during normal, shutdown, and design basis i

!. accident conditions. In reaching this conclusion, the evaluation noted the following: .

i e As flowrate through the relief valve (at lift setpoint  :

pressure) was approximately 40 gpm, the loss of inventory l 4

was within charging system capacity (44 gpm per pump).

r e 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 a high pressure suction source and the relief valve's lift setpoint would not be challenged.

q e -The relief valve in question discharged to a floor drain '

which directed flow to the safeguards room sump. The sump was designed to be pumped 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 sump overfilled) would not rise to the level of the HPSI pump motors until approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> after the lift. Before this time elapsed, the licensee reasoned that sump high level alarms  :

would alert operators to the event, allowing operator l intervention prior to the loss of the HPSI pump.

e The licensee noted that, while SDC was assumed to be placed in service during postulated small break LOCAs, ESDEs, and SGTRs (when RCS pressure may have been high enough to have led to a relief valve lift), the FSAR analysis demonstrated that fuel-damage (and thus-the release of significant amounts of radioactive material'to the RCS) was involved only because of extremely conservative assumptions. The evaluation went 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 will not be increased and the FSAR offsite doses remain bounding."

l 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 V343g," 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 j

i .

I 5

4 l consequences of a less significant set of accidents and concluded, t

without providing quantitative results, that the radiological >

i

-consequences of design basis accidents bounded the'noted relief i

valve lift. While the inspector. agreed with the licensee's t position that the circumstances assumed in design basis accidents

were, probabilistically, of low likelihood, the inspector pointed out that the assumptions were the approved licensing basis 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 j consider the issue.

D. Licensee Corrective Actions '

4 4

On August 12, the inspector requested ~ data on appror.imately 25 .

I relief valves on both units which communicated with the RCS in some way. The requested data included lift and blowdown i setpoints, tolerances, relief capacity, and normal operating  !

pressures experienced by the valves. Shortly after requesting the i

' information, the licensee informed the inspector that a team had ,

been formed to evaluate all safety-related relief valve data. The 1

i team included members from Engineering, Maintenance, Operations, Tech Staff, and Licensing.

The team's review was documented in JPN-SPSL-95-0334, "St. Lucie  ;

Units 1 and 2 Design Review of Safety Related 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 margin to lift and blowdown margin (the difference between ressat pressure and normal system operating pressure). The document reported that, of 114 relief valves reviewed, 8 valves on Unit 1

i. and 5 valves on Unit 2 required further review due to unacceptable margins of lift or blowdown. Corrective Actions were specified for the following valves:

, Unit 1 Valves F

e V2324, V2325, and V2326 - Charging Pump Discharge Relief f

Valves - MEP 107-195M was issued to reduce the design superimposed backpressure from 165 psig to 115 psig.

e 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.  !

1 4 e V3412 - HPSI IB Discharge Header Relief Valve - EP 115-95 j i was issued to increase the design setpoint from 1735 psig*to 1750 psig and to reduce blowdown from 25 percent to 10 percent.

4 y

i 6

! e V3417 - HPSI Pump 1A Discharge High Pressure Header Relief

. Valve -design setpoint increased from 2400 psig to 2485 psig 1 and blowdown reduced from 25 percent to 15 percent. >

e V3468 and V3483 - SDC Suction Relief Valves - STAR 950430 was issued to evaluate new setpoints and blowdown values.

Unit 2. Valves e V2345 - Letdown Relief Valve - At the close of the inspection period, an EP was being prepared to implement actions similar to those implemented on Unit 1 for this valve.

e 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.

e V3417 - HPSI Pump 2A Discharge High Pressure Header Relief Valve - At the close of the inspection period, an EP was being prepared to increase the valve's setpoint from 2400 psig to 2485 psig and to reduce blowdown from 25 percent to 10 percent.

e 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 i psig to 535 psig.

1 As a result of the licensee's investigation, and through  !

discussions with vendors, the licensee determined that some relief valves had beeri 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) was considering the 10 CFR 21 ramifications of the issue.

The licensee documented the conditions on STAR 951024. The inspector reviewed the STAR and noted that it tad 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:

e 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 ressat. .

P

• *e

.l l

7 e STAR 0-950234,- initiated March 2, documented the fact that relief valves had lifted and that blowdown values placed the ,

reseat pressure of the valves in the operating ranges of the 1 systems they protected.

e STAR 1-950269, initiated March 10, documented relief valve lifts on the Unit 1 CVCS letdown line during evolutions j which should not have challenged the valve's setpoint. j i

e STAR 0-950917, initiated August 18, documented the subject i SDC relief valve lift. l In addition to the STARS referenced above, IR 95-05-01 discussed work performed on the Unit 2 CVCS system to prevent letdown line relief valve lifts. The IR also described the failure of the relief valve to resent (once lifted) due to a blowdown value which l placed the reseat pressure below the system's normal operating )

pressure.

The inspector reviewed the status 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 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:

o Completion of SRV test benches, which would allow the licensee to better set and test SRVs for lift setpoint and accumulation. It was noted that the bench had only limited blowdown test capability.

e Performing an engineering design basis review of all safety related SRVs to validate or correct setpoints and issue a design document that summarizes the design data.  ;

• Enhancing journeyman training on SRVs.

While the inspector found the licensee's proposed 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-related items were addressed prior to forwarding the STAR to engineering.  ;

E. Conclusion ,

The inspector found that the licensee's corrective actions for the valves potentially affected by the subject event were comprehensive and sound. However, the inspector concluded that the actions could have reasonably been expected to be performed in

=fQQ&y., .

, - , . ,. ,, ,- r- - -e-

8 a much more timely fas'hion. The subject phenomenon was identified as early as February,1995, and repeated itself on no less than 3 separate systenis, and on both units, prior to the' most recent event. Once focused on the issue, an engineering product of high quality was developed, and corrective actions initiated, in '

approximately 2 weeks and identified valves requiring attention in a comprehensive action. 10 CFR 50, Appendix B, Criterion XVI,

" Corrective Actions," requires, in part, that measures be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, prompt corrective action was not taken in the case of St. Lucie Action Requests, which reported anomalous relief valve behavior, that were initiated on February 20, March 2, and March 10, 1995. The failure to take prompt corrective action for these conditions led to a repetition of the anomalous behavior on August 10, 1995, when Unit I relief valve V-3439 lifted and failed to reseat without operator intervention. The subject event resulted in approximately 4000 gallons of reactor coolant accumulating in the Unit 1 pipe tunnel. The failure to take prompt corrective action is an apparent violation (EEI 335/95-20-01, Failure to Take Prompt Corrective Action on Relief Valve Deficiencies).

3. Exit Interview The inspection scope and findings were summarized on October 10, 1995, with those persons indicated in paragraph I above. The inspector described the areas inspected and discussed in detail the inspection results listed below. Proprietary material is not contained in this report. Dissenting comments were not' received from the licensee.

Tyn Item Number Status Description EEI 50-335/95-20-01 Open " Failure to Take Prompt Corrective Actions for Relief Valve Deficiencies," paragraph l 2.

4. Abbreviations, Acronyms, and Initialisms AE00 Office of Analysis and Evaluation of Operational Data ANPS Assistant Nuclear Plant Supervisor' CCW Component Cooling Water CFR Code of Federal Regulations CVCS Chemical & Volume Control System DPR Demonstration Power Reactor (A type of operating license)

EEI Escalated Enforcement Issue EP Engineering Package

. ESDE Excessive Steam Demand Event FCV Flow Control Valve FPL The Florida Power & Light Company

59lWR >l

i~

3 9

, FR Federal Regulation FSAR Final Safety Analysis Report gpm Gallon (s) Per Minute (flow rate) l- HCV Hydraulic Control Valve i HPSI . High Pressure Safety Injection (system)

IR- [NRC) Inspection Report JPN (Juno Beach) Nuclear Engineering LOCA Loss of Coolant Accident LPSI Low Pressure Safety Injection (system)

NPF Nuclear Production Facility (a type of operating license)

NRC Nuclear Regulatory Commission NRR NRC Office of Nuclear Reactor Regulation NWE Nuclear Watch Engineer ONOP Off Normal Operating Procedure OP Operating Procedure PORV Power Operated Relief Valve psia Pounds per square inch (absolute) psid Pounds per square inch (differential) lpsig Pounds per square inch (gage)

PSL Plant St. Lucie QA Quality Assurance QC Quality Control RAB Reactor Auxiliary Building RCS Reactor Coolant System -

RII Region II - Atlanta, Georgia (NRC)

RWT Refueling Water. Tank SDC Shut Down Cooling SGTR Steam Generator Tube Rupture SNPO Senior Nuclear Plant (unlicensed] Operator SRV Safety Relief Valve

'URI [NRC] Unresolved Item VCT Volume Control Tank VIO Violation (of NRC requirements)

I

- s m,

. .3, , Q .,

1 . .

ESCALATED ENFORCEMENT PANEL QUESTIONNAIRE INFORMATION REQUIRED TO BE AVAILABLE FOR Et!FORCEMENT PANEL PREPARED BY: R. Prevatte 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: 50-335 License Nos: DPR-67 Inspection Dates: July 30 - September 16. 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 Director and each violation includes the appropriate level of specificity as to how and when the requirement was violated.

[] Copies of applicable Technical Specifications ur 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.C.2.B

4. What is the apparent root cause of the violation or problem?

Enaineerina evaluation and orioritization of potential eauipment oroblem was not timely.

5. State the message that should be given to the licensee (and industry) through this enforcement action.

Imorove crioritization and timeliness of response to plant oroblems.

6. Factual information related to the following civil penalty escalation or

. . - . . . _ - . _ . . _ . _ _ _ _ . _ _ . - . - _ . ~ . _ _ _ _ _ _ _ . _ . . _ _ _ . _ . . _ _ _

e i

mitigation factors (see attached matrix and 10 CFR Part 2, Appendix C, Section VI.B.2.): ..

i. t

a. IDENTIFICATION: (Who identified the violation? What were the i facts and circumstances related to the discovery of the violation?--

a Was it self-disclosing? Was it identified as a result of a generic notification?)

i

! Licensee identified anomalous behavior of safety related thermal

!- relief valves on February 20. March 2. and March 10. 1995, but did

,. not take action until a failure also occurred on Auaust 10. 1995

j. and NRC auestioned corrective action.

.- t. CORRECTIVE ACTION: Although we expect to learn more information regarding corrective action at the enforcement conference, i describe preliminary information obtained during the inspection .

and exit interview.

See item A. ,

j What were'the immediate corrective actions taken upon discovery of the violation, the development and implementation of long-term

~

j corrective action and the timeliness of corrective actions?

1

Initial oroblem was under enaineerina review for soveral months.

, 8figr auestionina by NRC. the problem was thorouch'y researched i and corrected.

i.

1 What was the degree of licensee initiative to address the l violation and the adequacy of root cause analysis?-

3 l Initial - not timelv.

i Final - cood investication and broadened scope led to review of over 100 relief valves.

c. LICENSEE PERFORMANCE: This factor takes into account the last two ,

years or the period within the last two inspections, whichever is i longer.

List past violations that may be related to the current violation I (include specific requirement cited and the date issued):

NCU 94-25-01. Inadeounte desian control of NADH suction relief va ves. ,

VIO 94-11-01. Mnadeaunte corrective action for M0V which stalled '

durina surveil' ance.

I VIO 94-12-01. IE swina bus would not strio on undervoltaae due to wirina oroblem 94-08-01. Inadeauate corrective action on waterhammer event.

l

'I

+

8

[' Inocerable snubbers and SRV PORV tailoices.

94-08-02. Failure to document above non-conformance.

94-06-02. Inadeauate desian control on Unit 2 charoina oumo seauence.

94-06-01. Failure to report DG failure.

I Identify the applicable SALP category, the rating for this I category and the overall rating for the last two SALP periods, as

well.as any trend indicated:

Ena. Support 1 - 1 l

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?

Problem known but not oursued.

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.

No.

f. DURATION: How long did the violation exist?

Problem has existed on thermal relief valves since initial installation.

ADDITIONAL COMMENTS / NOTES: .

5) S'nutdown 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 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 as the LPSI pump was started.  ;

As corrective action, the licensee revised OP 1-0410022, " Shutdown Cooling," to change the methodology i of starting the LPSI pump to the following:

I e Shut LPSI pump discharge isolation and LPSI header isolation valves e Start the LPSI pump . . .

e Immediately open the LPSI pump isolation valve 1 e Throttle open two LPSI header isolations to 150 l gpm per header j e Run for 15 minutes i e Start the second pump l e Throttle open the remaining LPSI header i isolation valves to 150 gpm per header. j e Wait 5 minutes r e Incrementally open header isolation valves'to  !

, obtain full flow.  !

The licensee reasoned that this methodology would i result in a slow increase in flow, . allowing controlled  ;

system heatup and minimizing the potential for water ,

hammer.  !

B. LPSI Discharge Isolation Valve Lift f

On August 10, while placing the Unit 1 SDC system in service to support a cooldown required due to.

inoperable PORVs (see IR 335/95-16), V-3439, the A

-LPSI header thermal relief, lifted resulting in a loss '

of approximately 3500-4000 gallons of RCS coolant in the Unit 1 Pipe tunnel. The following timeline was t developed from operator interviews, logs and instrumentation data:

0018 A LPSI pump start (ANPS, NWE, Logs)

Pressurizer level begins to drop (strip chart data)

h 0025 ANPS directs SNP0 to tour pipe tunnel due to minor reduction in pressurizer level (ANPS)

No increases in HUT, RWT, etc not 1 (ANPS) '

SNPO reports no unusual conditions in pipe tunnel '

0105 B LPSI pump start (ANPS, NWE, Log)

Pressurizer level recovers and oscillates (strip chart)-

0140 Cooldown flow established (ANPS, NWE)  :

0210 Fire watch calls control room, reports water issuing from watertight door isolating pipe tunnel from RAB (ANPS, NWE) .

0215 SDC secured (ANPS, NWE)

Pressurizer level increases and stabilizes ,

(strip chart)  ;

0226 Floor drain isolation valves (FCV 25-1 through '

7) 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) i Operators cycle v&rious 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 valve lift was a pressure surge while LPSI pumps were operating in a low-flow condition. The combination of i RS pressure (a maximum of 267 psia at the time) and LPD pump diccharge head at essentially no flow  !

(approximately 182 psid) combi.7ed with possible perturbations (when starting the pump) was considered '

enough to challenge the relief valve setpoint (485-515). This condition existed frcm the time the 1A LPSI pump discharge isolation valve was opened until operators initiated flow through the LPSI header ,

isclation valves.

V-3439 was designed to provide a 10 percent blowdown, which, if applied to the lower acceptable lift i

.setpoint of the valva (485 psig), would require a 48.5 .

I psia reduction in pressure to allow reseat. Given  !

t these sarameters, should V-3439 open, RCS pressure would inve 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 resent +

until significant volumes of coolant were lost.

The volume of coolant lost during the event was

i i

1 i estimated by the inspector, based upon floor layouts i as displayed on drawings.- Given water depths reported i by the NWE (up to approximately 14" in some areas),

the inspector estimated that approximately 3500

) gallons were lost. The CVCS makeup integrator,  :

i measuring volume added to the VCT in maintaining i i

pressurizer level on setpoint, indicated that 4000 gallons were added to the VCT.

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 l

l conducted by control room operators, .some of the

- valves had failed to stroke properly. As a result, i the valves were left closed for troubleshooting and

were never reopened. OP 1-0010123, Rev 99, i i " Administrative Control of Valves, Locks, and

! Switches," required, in step 8.1.6, that "All valve or j switch position deviations or lock openings shall be '

l documented in Appendix C, Valve Switch Deviation

Log..." The inspector reviewed archived Appendix C l j logs completed in July and August and control room i open Appendix C logs and found no evidence that HCV-

25-1 through 7 were logged as being out of position.

o The failure to enter the valves' closed status into i the valve deviation log is an example of a violation  ;

j (VIO 335/95-15-01, " Failure to Follow Procedures,"

[ Example 4). STAR 950917 was initiated to develop a PM l for verifying that floor drains were unclogged. ,

1

The licensee prepared an evaluation of the effects of ,

l the subject setpoint/ blowdown values on plant j

operation. JPN-PSL-SENP-95-101, Rev 1, " Assessment of -

l the Effects on Plant Operation of Lifting the LPSI '

i Pump Discharge Header Thermal Relief Valve," concluded j that the subject condition would not have a

significant effect on safe plant operation during i normal, shutdown, and design basis accident i conditions. In reaching this conclusion, the i

evaluation noted the following:

e As flowrate through the relief valve (at lift setpoint pressure) was approximately 40 gpe, the i loss of inventory was within charging system capacity (44 gpa per pump).

e 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 a high pressure suction source and the relief valve's lift setpoint would not be challenged.

t I

i J

i l e The relief valve in question discharged to a floor drain which directed flow to the 1 safeguards room sump. The sump was designed to be pumped down in level to the EDT automatically  ;

) when offsite power is available. Thus, with i offsite power available, no flooding hazard i i would exist. Under conditions with no offsite '

power available, the water level in the ,

safeguards room (after the sump overfilled)- '

] would not rise to the level of the HPSI pump i motors until approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> after the  !

lift. Before this time elapsed, the licensee i

reasoned that sump high level alarms would alert operators to the event, allowing operator 3

}

1 intervention prior to the loss of the HPSI pump. l e The licensee noted'that, while SDC was assumed to be placed in service during postulated small

break LOCAs, ESDEs, and SGTRs (when RCS pressure  ;

may have been high enough to have led to a relief. valve lift), the FSAR analysis j demonstrated that fuel damage (and thus the  ;

i release of significant amounts of radioactive '

material to the RCS) was involved only because i

of extremely conservative assumptions. The I evaluation went on to state that "A review of

FSAR analysis of small break LOCAs, ESDEs and l

SGTRs demonstrates that these accidents will not i result in fuel damage if assumptions that ]

i reflect the actual operating history of the '

plant are applied. .Therefore, the radiological

! consequences of these FSAR accidents will not be

! increased and the FSAR offsite doses remain l bounding."

The inspector took exception to the licensee's i conclusion. The subject passage was included in 2 Section 4 of the evaluation, " Analysis of Effects of 1 Lifting V3439," in a section entitled " Increases in  !

' Radiological Consequences of Design Basis Accidents."  !

The inspector found that, in choosing.to. neglect _  ;

i design basis assumpti6hi~ih~~their analysis of the l f event (specifically, a return to power and fuel l i failure resulting from the most reactive rod failing i i 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,

&fh

.m -. , .

1 i I

! I i

i probablistically, of low likelihood, the inspector i pointed out that the assumptions were the approved i

licensing basis of the plant and, as such, provided

-the appropriate common ground upon which to evaluate 1

the event's significance. The inspector brought this .j to the attention of the licensee, who stated that they j would consider the issue. At the close of the I l.. inspection period, the licensee had not presented a  !

j 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 J l Loss of Inventory via V-3439").

' On August 12, the inspector requested data on .

approximately 25 relief valves on both units which i

communicated with the RCS in some way. The requested j data included lift'and blowdown setpoints, tolerances, j relief capacity, and normal operating pressures experienced by the valves. Shortly after requesting I

j. the information, the licensee informed the inspector that a team had been formed to evaluate all. safety-

' related relief valve data. The team included members from Engineering, Maintenance, Operations,-Tech Staff,

and Licensing.

The team's review was documented in JPN-SPSL-95-0334, l "St. Lucie Units I and 2 Design Review of Safety i i'

Related 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, i relief valve setpoint, and blowdown. Relief valves l , were evaluated for their margin to lift and blowdown i

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 l review due to unacceptable margins of lift or 2

blowdown. Corrective Actior:s were specified for the j -

following valves:

1 3

Unit i Valvei 4

e V2324, V2325, and V2326 - Charging Pump Discharge Relief Valves - MEP 107-195M was l -

issued to reduce the design superimposed backpreswrs from 165 psig to 115 psig.

e V2345 - Letdown Relief Valve - PC/M 108-195

1. issued to reduce letdown backpressure to 430 l psig and to reduce the valve's blowdown from 25 percent to 15 percent. ,, ,

e V3412 - HPSI IB Discharge Header Relief Valve - _

, s % M .'

{ .% mi i _. - -

i e

EP 115-95 was issued to increase the design I setpoint from 1735 psig to 1750 psig and to ,

reduce blowdown from 25 percent to 10 percent. 1

e V3417 - HPSI Pump 1A Discharge High Pressure . -

d Header Relief Valve -design setpoint increased from 2400 psig to 2485 psig and blowdown reduced

[ from 25 percent to 15 percent.

e V3468 and V3483 - SDC Suction Relief Valves -

STAR 950430 was issued to evaluate new setpoints

and blowdown values. i Unit 2 Valves i

e V2345 - Letdown Relief Valve - At the close of the inspection period, an EP was being prepared l

to implement actions similar to those  !

4 implemented on Unit I for this valve.  !

! e V3412 - HPSI 2B Discharge High Pressure Header Relief Valve - At the close of the inspection j period,'an EP was being prepared to reduce

blowdown from 25 percent to 10 pacent.

e V3417 - HPSI Pump 2A Discharge High Pressure

! Header Relief Valve - At the close of the

inspection period, an EP was being prepared to j increase the valve's setpoint from 2400 psig to 2485 psig and to reduce blowdown from 25 percent to 10 percent.

l e V3439 and V3507 - Low Pressure A and B Discharge

! Relief Valves - At the close of the inspection j period, an EP was being prepared to increase the 1 valve's setpoint from 500 psig to 535 psig.

i As a result of the licensee's investigation, and

through discussions with vendors, the licensee determined that some relief valves had been provided 1 with unacceptably high blowdown values. This was,

- ipiiirent19, dse to pr6cidural ~ problems at the vandcr's test facility. At the close of the inspection period,

the vendor (Crosby) was considering the 10 CFR 21

ramifications of the issue. The licensee documented '

i . 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. , -

.. p g. M . p. .. .

The inspector reviewed the licensee's STAR database ,

says i  %.,e .

l for events similar to the subject event and found the following:

e STAR 2-950167, initiated February 20, d'::umented  ;

the lifting of SDC heat exchanger CCW ralter ,

valve SR-14350 when stroking CCW "N" header  !

isolation valves closed. Once open, the relief l valve had to be isolated (by closing an upstream i valve in the process line) to bring about a i reseat. .

e STAR 0-950234, initiated March 2, documented the  :

fact that relief valves had lifted and -that blowdown values placed the reseat pressure of the valves in the operating ranges of the systems they protected. l e STAR 1-950269, initiated March 10, documented relief valve lifts on the Unit 1 CVCS letdown line during evolutions which should not have challenged the valve's setpoint. t e STAR 0-950917, initiated August 18, documented the subject SDC relief valve lift.

In addition to the S1ARs referenced above, IR 95-05-01 discussed work performed en the Unit 2 CVCS system to  :

prevent letdown line relief valve lifts. The IR also described the failure of the relief valve to ressat ,

(once lifted) due to a blowdown value which placed the reseat pressure below the system's normal operating  ;

pressure. ,

The inspector reviewed the status 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 setting blowdown values on the valves in question, rather than on the appropriateness of the setpoints themselves. The licensee offered STAR 950_234_as being illustrative of this point. The proposed corrective actions included:

e completion of SRV test benches, which would allow the licensee to better set and test SRVs for lift setpoint and accumulation. It was noted that the bench had only limited blowdown test capability.

e Performing an engineering design basis review of all safety related SRVs to validate or correct setpoints and issue a design document that- v4 '

summarizes the design data.

' ?f

,y

l e Enhancing journeyman training on SRVs.

While the inspector found the licensee's proposed <

activities prudent, it was noted that nothing )

precluded engineering from addressing the setpoint I issue earlier in the process. The licensee stated that the STAR was addressed in stepwise fashion and that the maintenance-related items were addressed prior to forwarding the STAR to engineering.

1 The inspector fou'nd that the licensee's corrective actions for the subject event were comprehensive and

sound. However, the inspector concluded that the actions could have reasonably been expected to be performed in a much more timely fashion. The subject phenomenon was identified as early as February,1994, and repeated itself on no less than 3 separate systems, and on both units, prior to the most recent event. Once focused on the issue, an engineering product of high quality was developed, and corrective actions initiated, in approximately 2 weeks and identified valves requiring attention in a

! comprehensive action. 10 CFR 50, Appendix B required i that, for conditions adverse to quality, prompt  !

i corrective action be taken to prevent recurrence.

l 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 Corrective Actions for Repeated Relief Valve Lifts").

1 4

4 e

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h

1 Proposed Violation 10 CFR 50, Appendix B, Criterion XVI, " Corrective Actions," requires, in part, that measures be established to assure that conditions adverse to quality are promptly identified and corrected, Contrary to the above, prompt corrective action was not taken in the case of St. Lucie Action Requests which reported anomalous relief valve '

behavior and which were initiated on February 20, March 2, and March 10, 1995. The failure to take prompt corrective action for these conditions led to a repetition of the anocalous behavior on August 10, 1995, when Unit I relief valve V-3439 lifted and failed to reseat without operator intervention. The subject event resulted in approximately 4000 gallons of reactor coolant accumulating in the Unit 1 pipe tunnel.

This is a Severity Level III violation (Supplement I).

4 A

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Proposed Violation 10 CFR 50, Appendix B, Criterion XVI, " Corrective Actions," requires, in l l part, that measures be established to assure that conditions adverse to quality are promptly identified and corrected, ,

l d

Contrary to the above, prompt corrective action was not taken in the case of St. Lucie Action Requests which reported anomalous relief valve l behavior and which were initiated on February 20, March 2, and March 10, l 1995. The failure to take prompt corrective action for these conditions H led to a repetition of the anomalous behavior on August 10, 1995, when i Unit I relief valve V-3439 lifted and failed to reseat without operator

intervention. The subject event resulted in approximately 4000 gallons '

of reactor coolant accumulating in the Unit I pipe tunnel.

This is a Severity Level III violation (Supplement I).

a 4

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Fitrid. P;wir & Light Company, P.O. Box 128. Fort Pierce. FL 34954-0128 August '2, 2 1995 l

1

! .k cc wJ CS D- P -

L-95-239 10 CFR 50.73 4

U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 d

Re: St. Lucie Unit 1 i

Docket No. 50-335

' Reportable Event: 95-006 i Date of Event: . August 10, 1995 Loss of Reactor Coolant Inventory Through a J

Shutdown Coolina Relief Valve Due to Lack of Desian Marain i

I The attached Licensee the requirements Event50.73 of 10 CFR Report is being submitted pursuant to subject event. to provide notification of the 4

Very truly yours, D. A. ger

. Vice sident St. Lucia Plant DAS/GRM Attachment 3 cc: Stewart.D. Ebneter, Regional Administratur, USNRC Region'II Senior Resident Inspector, USNRC, St. Lucie Plant

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! NRC PORM 366 U.5. NV 2 _a = = =^ TORT GG. 3

( 4 95) AMROWsD sY oms NO. 3150 elet I

i EXPN5 04f30ms j afmano suRoEN fER RSPONE TO COMPLY wm4 That MAND Y 1 LICENSEE EVENT REPORT (LER) neoRManow

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d "cI O " ANosu E e T E j ,AcanT Nape C) 1 -- ' E - R FE8E R i St. Lucie Unit 1 05000335 i OF 5 Tma m i

Loss of Reactor Coolant inventory Through a Shutdown Cooling Relief Valve due to 1.ack of Desi EVENT DATE (5) LER NUMsER (6)

REPORT DATE (7)

OTHEL FACIUTM3 INVOLVE) (s)

MONTH DAY YEAA YEAR PAcanT waes MONTH DAY -i wumm YEAR j

• 08 racanT k j 10 95 95 - 006 - 00 08 22 95 Docxf7 Nunan gfg

! O,ERArma 4 TH= -' = m- a w P ==. ANT TO THE mar Z M OF 10 CFR % N or more NODE (9) ?n no (b) W)

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OTHER

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"^"' u1== CONTACT FOR THIE LaR (I2) mnwoneuuma m .,.c ,

KellyJ. Korth, Shift Technical Advisor I i (407) 465-3550 x3580 1

COi W.EH ONE UNE FOR EAhi COMPONENT FM DibCnisID IN TMl5 RiiN.ma (13) f suss sysnN COMPONENT MANUFACTURER R

ORjRDS P

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j Supptr =,TAL REKmT EXm. w (14) MONTH DAY

. TEAR TEs (W yes. comp 6ese EXPECTED SUsMt5510N DATE). X NO -

DATE (15) j ARETRACT (umt to 6400 & La, approomosepy I5 sinpe speted typewriaen knes) (16) 1 i At 0018 on August 10,1995, Unit 1 was in Mode 4 in the process of cooling down and depressurizing the Reactor Coolant System (RCS) to investigate the failure cf the Power Operated i

Relief Valves (PORV). The 1 A Low Pressure Safety injection (LPSI) pump was started to initiate flow for Shutdown Cooling (SDC) operation. A thermal relief in the common LPSI discharge piping, lifted during the pump start and did not reseat. SDC operation continued until 021!!, August 10, when the i lifting relief was discovered and the LPSI pump was stopped.

i

' The root cause of the event was the lack of design margin between the relief valve lifting and ressating setpoints and normal SDC system pressure.

(

Corrective actions include: 1) The lift setpoint pressure was increased and tne minimum required blowdown was reduced, 2) The LPSI thermal relief valve was replaced, and 3) The available design margin for 114 other Safety Related relief valves on both St Lucie units has been evaluated.17 of these valves will require additional analysis and actions will be taken to increase the margin between j +

t,ystem operating pressure and the lifthesset setpoints where appropriate.

I l

1 A

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l NRC PORM 366 (&M)

I

__ _ ________ __._ _ _ _ _ __ ._ , . . , , , _ . . . . .y . . . , y. , - - .

f emc ev.iri 366A l ('M) WA NUCLEAR AEGULAsum COMMEBON LICENSEE EVENT REPORT (LER) j- TEXT CONTINUATION FAClurr M (1) @ =z r LER NuMsER (6) PAGE (3) i

' St Lucie Unic I 05000335 "l W ' N 95 - 006 2 OF 5 i -

00

{ TsAT (if . .e e space as regiared, use sadoonal copses o( NRC fo,m J66A) (IT) i j DESCRIPTION OF THE EVENT i

On August 9,1995, Unit 1 was in Mode 4 with both Reactor Coolant System (RCS) (Ells:AB) loops, j

and their associated Steam Generators (SGs) available for residual heat removal. The Power Operated  ;

j Relief Valves (PORVs) (Ells:AB) had failed to open during stroke testing (Reference LER 335/95-005-

00). Per the applicable Technical Specification (TS) action statement, the RCS was to be cooled down

and depressurized.

i l At 0018 on August 10,1995, with the unit in Mode 4 at 278 degrees and 261 psia, the 1 A Low Pressure Safety injection (LPSI) (Ells:BP) pump was started to place the Shutdown Cooling (SDC)

(Ells:BP) system in service to continue with the cooldown. Shortly after starting the LPSI pump, utility i licensed operators identified that Pressurizer level and Letdown flow were decreasing. The operators did not receive any annunciators normally associated with RCS leakage, did not observe any increase in reactor cavity sump flow and did not detect any level increases in the wasta management sumps or j tanks (Ells:WD) Utility non-licensed operators were dispatched to investigate. Inspections of the LPSI i

pump rooms and other areas in the Reactor Auxiliary Building (RAB) did not identify any leakage.

j Based on the lack of any confirmatory indications of leakage, the operators concluded that the

{ charging / letdown mismatch was the result of the RCS cooldown. At 0105, the 1B LPSI pump was started and the remaining steps in the SDC normal operating procedure were completed.

At 0215 on August 10,1995, the control room was notified by the roving fire watch that water was j accumulating in the -0.5 ft. elevation of the RAB in the pipe tunnel. Both trains of SDC were j immediately secured. The RCS heat removal safety function was being met by the Reactor Coolant

Loops and associated Steam Generators. Pressurizer level and charging / letdown flow were observed j to be stable, indicating that the leakage had stopped. A control room operator discovered that the RAB (Ells

NF) floor drain isolation valves to the Safeguards Pump Room sump were closed. When

! these valves were opened, the high sump level annunciator was received. Visual observation of equipment and piping in the pipe tunnel did not reveal any continuing source of the leakage. l Immediately after the event, the flow rate and total amount of leakage was not known. The j Emergency Plan implementing Procedures (EPIPs) were consulted and it was determined that i emergency notification was not required.'  !

Based on data evaluated following the event (Charging System makeup water integrator and level l increases in the Weste Management System tanks), it was estimated that approximately 4000 gallons of Shutdown Cooling inventory had been diverted to the RAB Weste Management System. The aameplate flow specification of this relief valvo is 5 gpm, but communication with the valve vendor, l subsequently revealed that the valve had the capability to relieve up to 40 gpm.

At 0611, the 1 A LPSI pump was again started and a licensed utility operator, stationed in the pipe tunnel, observed that valve V3439, thermal relief valve in the common LPSI discharge pipmg, had I lifted. The LPSI pump was immediately secured and the relief resented. At 0940 on August 10, both SDC trains were placed out-of service to replace the thermal relief. Following replacement of the i thermal relief, at 0600 on August 11< both SDC trains were restored to operable status. The RCS was then cooled down and depressurized to Mode 5.

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St Lucie Unit 1 05000335 nan W W 3 OF 5 l 95 - 006 - 00 l TaAT CI more space a regures, use aseconal copes of NAC Form Je64) (17) e i CAUSE OF THE EVENT The root cause of the event was inadequate design margin between the relief valve lift and blowdown setpoints and normal SDC operating pressure.

The LPSI common discharge piping thermal relief had a lift setpoint of 500 psig +/- 3% (485 to 515

! psig) and a minimum blowdown of 10% (435 to 465 psig). The setpoint bench testing of the relief j following its removal, ranged from 480 psig to 500 psig.

i. The initial operating pressure when establishing SDC is a combination of RCS pressure, LPSI pump j differential pressure and a pressure spike due to dynamic forces when the LPSI pump discharge valve is initially opened. Considering that the maximum RCS pressure that the SDC system can be placed in

! service is 267 psia (SDC suction valves are prevented from opening by an interlock until Pressurizer j' pressure is below 267 psia), a peak LPSI pump discharge pressure of 487 psig can be developed and a maximum operating pressure of 457 psig can be established.

! Therefore, V3439 could lift during SDC initiation since the lift setpoint can be as low as 485 psig and l LPSI discharge pressure as high as 487 psig. The valve could then remain open since the resesting point can be as low as 435 psig and the steady state pressure of the SDC system could be as Ngh as 457 psig.

During a unit outage in February 1995 to repair Pressurizer Code Safety Valves on Unit 1, a LPSI suction relief valve lifted when SDC was initiated. A team was assembled to evaluate the event.

Based on the results of the evaluation, the SDC initiation procedure was changed. A LPSI pump is started with its discharge valve and all four LPSI injection valves ciosed. When the discharge valve is oper., a downstream pressure spike has been observed. Two irijection valves are then throttled opened and a flow of 150 gpm 17, established and maintained for 15 minutes. The other LPSI pump is started and the remaining valves are throttled open for 5 additional minutes. Flow is then increased slowly.

Since the LPSI injection valves are closed when the LPSI discharge valve is opened, this procedure change subjects the LPSI common discharge header thermal relief to a slightly higher dynamic .

pressure spike than previously experienced. Therefore, this procedure change may have reduced the operating pressure to lift /ressat setpoint margin of this relief valve.

The -bDty of the operators to detect and mitigate the relief valve lifting was hindered by the Safeguards Pump Room sump isolation valves being closed. On July 31, in preparations for Hurricane Erin, the Safeguards Pump Room sump isolation valves were stroked closed, but not all of the 7 valves controlled by a single switch, had shut. Following troubleshooting efforts, the control switch was allowed to remain in the close position. With the isolation valves closed, the flow path from the LPSI common header thermal relief valve taiipipe to the Safeguards Pump Room sump was isolated.

Therefore, the sump high level annunciators were not available to alert operators to the event.

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ANALYSIS OF THE EVENT r

This event is reportable under 10 CFR 50.73 (a)(2)(vii) as any event where a single cause or condition caused two independent trains or channels to become inoperable in a single system designed to: (a) l Shut down the reactor and maintain it in a safe shutdown condition; (b) Remove residual heat; (c) j Control the rt ; ease of radicactive material; or (d) Mitigate the consequences of an accident.  ;

1 An evaluation was performed to assess the effects of the LPSI common discharge header thermal relief valve lifting on plant operation and safety (Engineering Evaluation JPN-PSL-SENP-95-101). Only l SDC operation was considered, where LPSI suction pressure is high enough to challenge the thermal i relief. SDC operation with the RCS depressurized or LPSI pump operation during the irijection and RCS hot leg recirculation phases of safety injection would have LPSI pump suction pressure sufficiently low such that adequate margin to the relief setpoint would exist. I The capacity of the thermal relief is approximately 40 gpm. Should the relief lift and not ressat during -

SDC operation, the rate of inventory loss would be well within the charging pump capacity and within '

the capability of the Waste Management System to remove the water such that Safety Related equipment would not be threatened. ,

SDC is relied on for long term cooling following certain design basis accidents, specifically: Small  !

Break Loss of Coolant Accidents (SBLOCAs), Excess Steam Demands, and Steam Generator Tube l Ruptures (SGTRs). The UFSAR analysis of these design basis accidents involve fuel damage only I when considering extremely conservative assumptions, if the conservatism is removed from the i analysis, it can be shown that no fuel damage will occur during these events. Therefore, the  ;

radiological consecuences from these design basis accidents, concurrent with the LPSI common '

discharge h3ader thermal relief valve lifting, will not be increased and the offsite doses of the UFSAR analysis remain bounding.

Per Technical Specification (TS) 3.4.1.3, with the plant in Mode 4, two of the four heat removal  !

system loops (Reactor Coolant Loops A and B with their associated Steam Generator and at least one associated Reactor Coolant Pump, and SDC loops A and B) shall be operable and at least one reactor l coolant or shutdown cooling loop shall be in operation. During this event, the plant was in Mode 4 i with both Reactor Cooling Loops operable and the B RCS Loop in operation. ]

The SDC system is protected from over pressurization during SDC operation by the LPSI suction reliefs. The thermal relief is only required whan the system is secured and the portion of piping between the LPSI injection valves and the LPSI discharge check valves is isolated.

Based on the justification listed above, the effect on plant operation due to the lack of design margin I between the LPSI common discharge header thermal relief valve setpoint and SDC operating pressures during SDC operation, either during normal plant cooldown or following design basis accidents, was not significant. The health and safety of the public were not affected by this event.

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CORRECTIVE ACTIONS

1) Engineering performed an evaluation to change the LPSI common discharge header thermal relief j valve lift setpoint and minimum blowdown to increase the design margin to the systems operating pressure.

2) The LPSI common discharge header thermal relief valve has been replaced with a new relief valve

with a lift setpoint of 535 psig and a blowdown range of 6 to 8%.

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3) The available design margin for 114 other Safety Related relief valves on both St Lucie units has been evaluated.17 of these valves require additional analysis and actions are being taken to increase the margin between system operating pressure and the lift / reseat setpoints where appropriate. The results of this review will be made available to the industry via the INPO Nuclear Network. i

4) An operator aid is being developed that will provide expected charging / letdown mismatches to maintain a constant Pressurizer level for various cooldown rates.

5) This event will be included into Operations training for both licensed and non-licensed Operations personnel.

6) The Operation Department Supervisor has issued a Night Order reemphasizing the importance of documenting the condition of those components that are in an abnormal configuration in the Valve, Switch Deviation Log.

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7) The Emergency Plan implementation Procedures is under review to determine the appropriate notification threshold for this type of event. Based on this review, changes to the EPIPs will be made if appropriate.

ADDITIONAL INFORMATION

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Failed Comoonent identification Manufacturer: Crosby Valve & Gage Co.

Model Number: JB 35S-TD SPEC Device LPSI Common Discharge Header Thermal Relief Valve Previous Similar Events LER 335-95-003 described the actuation of a letdown relief that did not ressat until operator action was taken, following an automatic reactor trip.

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