ML20134K852

Summary of ACRS ECCS Subcommittee 850731 Meeting w/B&W,C-E & Westinghouse in Washington,Dc Re Review of 10CFR50.46 & App K,Implementation of GE App K Analysis Effort & 850609 Incident at Facility

ML20134K852
Person / Time
Site:	Davis Besse
Issue date:	08/08/1985
From:	Advisory Committee on Reactor Safeguards
To:	Advisory Committee on Reactor Safeguards
References
ACRS-2341, NUDOCS 8508300468
Download: ML20134K852 (33)

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E [.3 ! f h f DATE ISSUED: 8/8/85 ACRS ECCS SUBCOMMITTEE Ff1jiS '

MEETING MINUTES JULY 31, 1985 WASHINGTON, DC PURPOSE: The purpose of the meeting was to: (1) review the proposed revision to 10 CFR 50.46 and Appendix K; (2) to review the implementa-tion of the GE Appendix K analysis effort; (3) discuss resolution of the issue of RCP trip given a SB LOCA; (4) review the report of the NRC investigation team regarding the J,une 9,1985 loss of all feedwater event at the Davis Besse plant; and, (5) discuss NRR's ECCS-related issues of ongoing concern.

ATTENDEES: Principal meeting attendees included:

ACRS NRC D. Ward, Chairman B. Sheron, NRR J. Ebersole, Member L. Shotkin, RES H. Etherington, Member W. Beckner, RES C. Mark, Member

• E. Throm, NRR G. Reed, Member

• K. Goetz, NRR C. Siess, Member

• N. Lauben, NRR F. Remick, Member

• E. Rossi, NRR P. Shewmon, Member

• C. Heltemes, AE00 C. Wylie, Member I. Catton, Consultant B&W V. Schrock, Consultant R. Schomaker i H. Sullivan, Consultant J. Paljug i

T. Theofanous, Consultant

! C. L. Tien, Consultant CE P. Boehnert, Staff G. Menzel l

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ECCS Meeting July 31, 1985 MEETING HIGHLIGHTS, AGREEMENTS AND REQUESTS

1. W. Beckner discussed the RES plan to revise 10 CFR 50.46 and Appendix K. The Staff approach is to allow best estimate calcu-lations, combined with uncertainty evaluations, to be used as EM's.

The existing Appendix K Rule would be grandfathered for licensees who do not wish to use the new approach. A draft of the new Rule has been developed. The major tasks remaining are te develop a Regul,atory Guide and " White Paper" (Research Report) that justifies the Rule change.

RES evaluated various options for the form of the Rule and support-

- ing implementation guidance. In response to Drs. Catton and Theofanous, RES said the focus of the effort will be to determine that the BE models give the "right answer for the right reasons".

In response to Mr. Ward, Dr. Beckner said RES wants a less pro-scriptive Rule because of the still-significant uncertainty in some LOCA models. RES/NRR has settled on the approach of a less specif-ic Rule (than currently in place), with guidance for implementation provided in a Regulatory Guide.

The schedule for the Rule change was noted (Fig. 1). RES expects to get the Rule and accompanying Regulatory Guide and research l Report (White Paper), to the Commission by December 1985. Dr.

Theofanous said the research Report should be issued with the Rule l in order to afford time for evaluation of this information. RES indicated the Report may not be available prior to issuance of the Rule and Regulatory Guide.

In response to Dr. Sullivan, Dr. Sheron (NRR) indicated that SECY 83-472 would be incorporated into the new Rule requirements.

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s ECCS Meeting July 31, 1985

2. Dr. Sheron discussed the status of SECY 83-472 which was instituted by the NRC Staff in late 1983. The general approach of 83-472 is that one can use a BE with the required Appendix K features as long as the subject ems calculated PCT is greater than the 95% certainty level of the BE calculated PCT.

To date, no one has applied for use of the 83-472 approach. NRR understands that the BWR-2 non-jet pump plants want to make use of this approach. They plan to submit a justification for use of the GE SAFER code in the fall of 1985.

As for the PWR licensees, W plans to make a model submittal in the fall of 1985 using COBRA-TRAC. The methodology for use of this new model will be submitted in Spring 1986 for 2-loop plants and in late 1986 for 4-loop plants. CE plans to submit a SB model in late fall 1985. B&W has no plans for any model submittals at this time.

Exxon plans model submittals in early 1987 (PWRs) and early 1988 (BWRs). Exxon is leaning toward use of TRAC for their new models.

Further Subcommittee discussion focused on the issue of model accuracy vis-a-vis uncertainty. NRC said they are not deemphasiz-ing model accuracy for a final right answer. Dr. Sheron said the NRC is not " selling the store" on this issue and that the Subcom-mittee and ACRS will be deeply involved in the reviews of the new models. He said the Staff is still on the learning curve and will eagerly seek ACRS guidance cn this effort.

In response to Dr. Su'.livan, Dr. Sheron said NRR has no concern with use of TRAC or RELAP-5 by the industry for licensing use. Dr.

Schrock asked if the generic decay heat curve has been approved for use by a prospective licensee. Dr. Sheron said a licensee will have to justify use of that curve or use of a plant specific curve.

Dr. Schrock said this item needs to be addressed in the draft l

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l ECCS Meeting July 31, 1985 Regulatory Guide. NRR agreed. Dr. Tien said whether or not one can even use the generic curve needs to be addressed. After further discussion, Dr. Sheron said he would check on this point with his Staff and discuss it at a future meeting of the Subcomit-tee.

3. The resolution of the TMI issue on RCP trip given a SB LOCA was I

reviewed. Representatives of B&W, CE and W made presentations.

NRR comented on their review of the vendor submittals. Highlights included:

• The B&W Owners Group position on RCP trip is: (1) RC pump trip is recomended for SB LOCA, (2) loss of subcooling margin is an appropriate signal indicating SB LOCA, and (3) RC pump trip can be achieved safely and reliably by the operator.

Dr. Schrock asked what decay heat curve was used for the BE SB LOCA trip setpoint. B&W said they would check on this point and inform the Subcomittee. Dr. Catton questioned whether B&W examined whether the RCPs should be tripped for an over-l cooling transient. B&W looked at mild overcooling transients but not severe transients. In response to Dr. Theofanous, B&W said they would supply infomation on the time needed to depressurize the RCS via a single PORV. In response to Mr. Ward, B&W said the AT0G procedures call for RCP trip on loss of subcooling and if the trip is a mistake - instructions are to restart the RCP's.

For a SGTR - a single SGTR will not result in loss of subcool-ing, therefore the pumps are lef t on. For rupture of more than one tube, the RCPs would be tripped on loss of subcooling margin. ,

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ECCS Meeting July 31,198:5

• G. Menzel (CE) discussed the CEOG/CE RCP trip strategy. The CE OG strategy is to " trip 2/ leave 2". The goals of this i strategy are to: (1) trip all RCPs for SB LOCAs to minimize inventory loss, (2) maintain forced coolant flow of at least two RCPs for non-LOCA's (SGTR, SLB) to maintain pressurizer spray and to minimize upper head voiding, (3) meet NRC guid-ance in generic letter 83-10. CE performed a BE analysis (Fig. 2) to demonstrate that if the second two RCPs are not turned off, or turned off at the worst time, the core remains cooled (PTC 4 2200*F). In response to Dr. Theofanous, Mr.

Menzel said the CE analysis shows that if four RCPs are left running for a SB LOCA the core will uncover in N10 minutes, if two are left running no core uncovery occurs. Dr.

Theofanous was skeptical of this result. CE reviewed the signals used for RCP trip (Fig. 3). In response to Mr. Ward, CE said the trip 2/ leave 2 strategy is awaiting NRC approval.

• y performed analyses to justify manual RCP trip. The princi-ple requirements for trip criteria are: (1)tripRCPswhen needed for SB LOCAs, and (2) maintain RCPs operational when beneficial to plant recovery (i.e., SGTR). Edevelopedthree criteria that a given plant can elect to implement. These criteria are to trip on either: (1) RCS wide-range pressure, (2) RCS subcooling, or (3) primary / secondary Delta-P. All three criteria have been shown to demonstrate adequate dis-crimination capability between SB LOCAs and other events for which RCP trip is not desirable as well as satisfy the re-quirements of Generic Letter 83-10. In response to Mr.

Ebersole,ysaideachplantwillsubmitaspecificRCPtrip criterion analysis. Ehasrunanalysesthatshowthatthere is at least 10 minutes of operator action time available to trip RCP's for a SB LOCA. The above trip criteria has been approved by the NRC.

ECCS Meeting July 31, 1985

4. NRR (E. Throm) discussed their review of the PWR vendors resolution of the RCP trip issue. The NRC Generic Letter (83-10) said manual RCP trip would be allowed if justified. Further, the licensees must demonstrate compliance with all NRC rules and regulations for manual RCP trip. Key points noted included:

• NRC approved the W manual RCP trip criterion in June 1985.

NRC has some plant-specific implementation issues to be addressed for W plants (Fig. 4). In response to Subcommittee concerns, Dr. Sheron said the whole aim of the NRC approach to this issue was to have the Industry assure the safest operat-ing mode for their plants - considering all aspects of RCP operation. In response to Mr. Etherington, NRC said Maine Yankee, Haddam Neck and Yankee Rowe are addressing resolution of this issue independent of the " generic" resolution ap-proaches discussed above.

• CE has also justified manual RCP trip and NRC approval is expected in August 1985. NRC has a residual concern with operationofessentialservicewaterforRCPoperation(Fig.

5). This is being addressed by the CE Owners Group.

• B&W has also justified manual RCP trip. NRC's SER should be issued in August 1985. A residual issue to be addressed concerns restoration of RCP seal bleedoff given a pump trip (Fig.6).

• Ors. Catton and Theofanous urged NRC to compare the vendor's

calculations of RPS inventory with NRC-sponsored calculations run with TRAC. NRC said they would make some comparisons and sutmit a report to the Subcommittee.

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ECCS Meeting July 31, 1985

5. Ms. K. Goetz (NRR) discussed the issue of the effect of multiple instrument tube failures at g plants vis-a-vis SB LOCA consid-erations. This concern arose when it was discovered that equipment located above the seal table is not seismically qualified (Fig. 7).

Failure of this equipment during a seismic event could result in rupture of one or more of the instrument tubes. Ehasdetermined that the worse case event wculd rupture no more than three tubes.

NRC calculations, done conservatively, show no core uncovery for rupture of at least six tubes. ,

NRC has sent an I&E Infomation Notice to all licensees and g has sent notice to its respective licensees. The Resident Inspectors are also checking for potential problems at their respective plants. In response to Mr. Ward, Dr. Sheron said NRC has not confirmed the E failure analysis. He said he would check what NRC follow-on actions, if any, are planned for this issue.

6. N.LaubenreviewedthestatusoftheE2-loopUPIECCSEMmodel revision effort. Figure 8 provides the details.

The current status of the Exxon ECCS EM model errors issue was also discussed (Figs.9-10).

Mr. Lauben also reviewed the recent problem discovered with the CE ECCS EM. The problem is similar to what was found with Exxon, i.e., the axial shaping curve used in the EM is flatter than originally assumed, resulting in a higher PCT. There is no safety problem due to the margin in the Appendix K analysis (Fig. 11).

7. E. Throm discussed the use of the nuclear plant analyzer (NPA) for analysis of the Davis Besse (DB) event. Unfortunately, problems with the INEL Computer, not the NPA software', prevented NRR getting any results of analysis of the DB event.

ECCS Meeting July 31, 1985 NRR had LANL run some analyses (Fig. 12) for support of the DB Investigative Team. The results obtained are preliminary, and LANL is polishing the output (Fig. 13).

8. E. Rossi overviewed the results of the NRC Investigative Team investigation of the Davis Besse loss of all feedwater event of June 9, 1985. A Report (NUREG-1154) has been released which details the results of the investi5ation. Key points of the presentation.were:

• The Team charter was to identify the root cause(s) of the event. They were not chartered to make any recommendations as a result of their work. ,

• Troubleshooting of the equipment failures seen is not yet complete. Therefore the root cause(s) of all failures hasn't been conclusively identified.

Figures 14-19 list the sequence of key events. Mr. Rossi detailed specifics of the event sequence.

• In response to Subcommittee questions, Mr. Beard noted that there were investigations conducted in parallel with the NRC j Team effort by both B&W and INP0. The B&W and INPO investiga-tions were conducted at the behest of the Utility. There was essentially'no interaction between the NRC and INP0/B&W investigations.

• There were a number of operator actions required to be per-formed outside the control room in order to restore AFW flow (Fig.20). ,

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ECCS Meeting July 31, 1985

• G. Reed said he believes the root cause of this event was poor plant and equipment design not poor maintenance practices.

J. Ebersole also echoed this opinion. Mr. Ward observed that had the plant been properly maintained, the event would most likely have not occurred.

• Results of the on-going troubleshooting of the failed equip-ment were reviewed (Figs. 21-22). In some cases, trouble-shooting will need to await plant operation to run hot tests (Item 4, Fig. 21).

• Human Factors aspects of the accident that were noted includ-ed: (1) the layout of the SFRCS co,ntrol panel contributed to the operator error which resulted in temporary isolation of both SG's as heat sinks, (2) operators did not follow emergen-cy procedure (feed and bleed not initiated when required per procedures, (3) difficulty in resetting AFW pump overspeed >

trips, (5) STA not required (arrived too late to be of help),

and (4) emergency notification was not timely or complete.

• The safety parameter display system was "down" during the event. The SPDS at DB has a poor reliability history. The Team believes had the SPDS been functional, it would have been an aid to the operators. During Subcommittee questions ,

however, Mr. Rossi indicated that the SPDS would not have been a crucial aid for recovery of this particular event.

• The major conclusion of the Team was that the underlying cause of the event was the licensee's lack of attention to detail in the care of plant equipment. The licensee has a history of performing troubleshooting, maintenance and testing of equip-ment, and of evaluation of operating ex'perience related to equipment in a superficial manner and, as a result, the root

ECCS Meeting July 31, 1985 causes of problems were not always found and corrected.

Operator interviews made clear that equipment problems were r,ct aggressively addressed and resolved beyond compliance with NRC regulatory requirements.

• Other key findings include:

• A key safety significance is that multiple equipment failures occurred.

• If safety-related auxiliary feedwater system equipment had functioned, operator error would not have had a signif,icant effect.

• Testing is likely to have detected causes of auxiliary feedwater system pump and valve malfunctions.

• Neither SFRCS (steam /feedwater rupture control system) nor the auxiliary feedwater system meet single failure criterion for all design basis accidents.

• Electric motor-driven startup feedwater pump availability improved safety margin.

• Operator understanding of procedures, designs, and equipment operation and operator training played a crucial role.

Locked doors and valves were a potential impediment to plant recovery.

• Some post-TMI improvements made positive contributions; others were not used.

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ECCS Meeting July 31, 1985

• Operator training and understanding of systems and equipment are key to success in mitigating events outside plant design basis.

• Operators at other plants may be reluctant to initiate make up/high pressure injection cooling without delay to consider alternatives.

• Instrumentation available on Ju'ne 9 was not adequate to inform operators that criteria for make up/high pressure injection cooling had been reached.

• Mr. Heltemes (AE00) said that the EDO will summarize actions for follow-on of the DB event and assign these actions to given NRC offices.

In resporse to Dr. Sullivan, Mr. Rossi said he believed the inves-tigative Team concept worked very well and should be repeated on all future significant events. The Subcommittee congratulated Mr.

Rossi for an excellent presentation and a job well-done by the Team.

9. The meeting was adjourned at 6:55 p.m.

NOTE: Additional meeting details can be obtained from a transcript of this n.eeting available in the NRC Public Document Room, 1717 H Street, N.W., Washington, D.C., or can be purchased from Ann Riley & Associates, Ltd., 1625 I Street, N.W., Suite 921, Washington, DC 20006 (202/293-3950).

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9 COMMISSION PAPER TO ED0 NOVEMBER 1985 REGULATORY GUIDE (DRAFT FOR COMMENT) NOVEMBER 1985 RESEARCH REPORT (DRAFT FOR COMMENT) DECEMBER 1985 l PAPER TO COMMISSION DECEMBER 1985 NOTICE OF PROPOSED RULEMAKING EARLY CY 1986 COMMENT PERIOD END MID-CY 1986 G

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CORE COOLING PERFORMANCE DURING WORST SBLOCA SCENARIO CONCERN:

WOULD CORE OVERHEAT DURING WORST SBLOCA IF SECOND TWO RCPs WERE LEFT RUNNING AND WOULD FAIL OR BE TURNED OFF AT WORST TIME ANALYSIS ASSUMPTIONS:

CONSERVATIVE BEST ESTIMATE MAJOR FEATURES:

o REFERENCE PLANT: 2700 MWT, o ECC FLOW FROM 1 HPSI TRAIN ONLY, MINIMUM FLOW o 1,0 MULTIPLIER ON 1971 ANS DECAY HEAT

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o HEM BREAK FLOW MODEL o TURBINE BY-PASS SYSTEM AVAILABLE OR STEAM GENERATOR SECONDARY SIDE PRESSURE AT STEAM SAFETY VALVE SETPOINT RESULTS1 PEAK CLADDING TEMPERATURE: 1200*F FOR TBS ANALYSIS 1660*F FOR SSV ANALYSIS T2/L2 STRATEGY INHERENTLY SAFE FOR REFERENCE PLANT (MOST ADVERSE CONDIT0NS), AND OTHERS

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SIGNALS FOR RCP TRIP BASIC APPROACH o SIMPLE-TO-INTERPRET SIGNALS o MINIMIZE NUMBERS OF SIGNALS o PROVIDE FEXIBILITY FOR PLANT-SPECIFIC IMPLEMENTATION o USE OF EXISTING INSTRUMENTATION o MEET HRC GUIDANCE (GENERIC LETTER 2-8-83)

SIGNALS USED o PRIMARY SYSTEM PRESSURE - FOR TRIPPING FIRST TWO RCPs

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o PRIMARY SYSTEM SUBC00 LING COMBINED WITH o CONTAINMENT RADIATION - FOR TRIPPING SECOND TWO RCPs AND/0R of ot# STEAM PLANT RADIATION _

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Reactor Coolant Pump Trip -

l Plant Specific Implementation Issues l

• Selection of Trip Criterion Instrumentation Uncertainties Normal / Adverse Containment

• Service Water Loss / Restoration Containment isolation Pump Seal Failure .

• RCP Trip Reliability  :

Components / Locations Normal / Adverse Containment I

• Operatfor Training & Procedures  ;

RCP Trip / Restart .

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Natural Circulation Cooldown ACRS July 31,1985 E.D.Throm,NRR/DSI/RSB f m

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Combustion Engineering RCP Trip i

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• CEOG response concerning i Essential Service Water for RCP operation was not accepta' ale

• Additional information requested ,

from CE licensees  :

• Information provided is currently

_. being reviewed , will be included  !

in SER f

• Most CE plants isolate essential l water on SI or high containment pressure, therefore rely on the operator to restore ACRS July 31,1985 E.D.Throm,NRR/DSI/RSB

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4 Babcock & Wilcox RCP Trip

• Seal bleedoff required, some ,

plants rely on ATOG to reset bleedoff, some plants redirect the bleedoff to quench tank

• CCW must be restored to a running pump l

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• BWOG recognizes use of a high-high containment pressure signal for isolation can resolve issue ACRS July 31,1985 E.D.Throm,NRR/DSI/RSB

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2 LOOP UPI-NDEL REVISION STATUS EETING WITH VENDORS AND UTILITIES TO DISCUSS PRELIMINARY PROPOSALS FOR NEW NDELS WESTINGHOUSE 1-10-85 .

COMBUSTION 2-12-85 EXXON -

3-6-85 UTILITIES MADE VENDOR SELECTIONS AND SUBMITTED EDEL DEVELORO(T PROGRAM PLANS T0 NRC IN MARCH AND APRIL 0

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• WESTINGHOUSE - PRAIRIE ISLAND, POINT BEACH COMBUSTION - KEWAUNEE, GINNA

• BOTH PLANS BASED ON 83-472 ETHODOLOGY FOLLOWUP E ETING WITH WESTINGHOUSE AND SELECTED UTILITIES ON 6-28-85

' FOLLOWUP WITH CE SCHEDULED FOR FALL 85

• EM SUBMITTAL TARGET DATES: .

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CE ECCS MODEL PROBLEM .

STATUS

• NO SAFETY PROBLEM, EXISTING l'DDELS E APPENDIX K HAVE MJCH

. MARGIN,

• WORST CASE IS TOP PEAKED WITH FZ = 1,52, MAINTAINED MAX Kw/FT, PCT IS INCREASED BY 34*F,

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• 3PLANISWOULDLIKELYEXCEED2200*FWITHCURRENTMODEL ,

PLANT CURRENT PCT SONGS 3 2183 WATERFORD 3 2188 PALO VERDE 2169

• SONGS 3 - CANNOT EXCEED Kw/FT, WHICH WOULD CAUSE PCT TO EXCEED 2200*F FOR BALANCE OF CYCLE 1 (40 DAYS) DUE TO DNBR LIMITS,

• WATERFORD - SUFFICIENT MARGIN BY NOT INCLUDING CONTAINMENT PURGE,

• PALO VERDE - HAS ADMINISTRATIVELY REDUCED PEAK LHGR BY 0.1 Kw/FT,

• ALL WILL CO MIT TO EVENTUAL REANALYSIS, d- aU t

Summary of LANL Analyses

• Requested by the Davis-Besse Incident investigation Team .

• Five Analyses

1. Plant Transient

2. Core Dryout

3. Feed / Bleed at SG Drybut

_ 4. Feed / Bleed 5 minutes later

5. Feed / Bleed 30 minutes after SG Iow level reached

• Cases 2 and 5 not yet done

• Case 1 resonable results

• Cases 3 and 4 sucessful ACRS July 31,1985 E.D.Throm,NRR/DSI/RSB

Summary of Stof f Simplified Davi.s-Besse Colculations i

SG CORE NININUN NO. OF ORYOUT SATURATION UNC0VERY RCS LIOUID CASE POWER HU RCTURTION TIME TIME TIME VOLUME NO. LEVEL PUNPS SUFP TINE NIN HIN HIN CU.FT.

I 100% 0 NO N/A 5 33 SS N/A 2 90% 0 NO N/A 4 35 60 N/A 3 75% 0 NO N/A 3' 40 72 N/A 4 90% 1 NO SG DRYOUT 4 45 99 N/A S 75% 1 NO SG DRYOUT 3 55 170 N/A

'6 100% 2 NO SG DRYOUT 5 46 N/A 3710 7 100% 2 NO 20 MINUTES 5 39 148 N/A 8 75% 2 NO SG DRYOUT 3 77- N/A 643S 9 100% 0 YES 20 MIN,UTES 5 46 120 N/A 10 100% 1 YES SG DRYOUT 5 xx N/0 10450 11 100% 1 YES 20 HINUTES 5 91 N/A >G43S 12 100% 2 YES 20 MINUTES 5 xx N/A 10450 13 90% 2 NO 10 HINUTES 4 50 N/A 5'433 Note 'l: LLquid volumo to top of core is 3470 cubi.c feet.

Note 2: ALL cases assume no depressuri.zati.on wi.th PORV.

xx  : System comoi.ns subcooled.

ACRS July 31, 198S E.D.Throm,NRR/OSI/RS8 5

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SEQUENCE OF EVENTS (CONTINUERl T = 6 3/4 MIN. AUXILIARY FEEDWATER PUMP' TURBINES TRIP ON OVERSPEED T=7 OPERATOR ERROR IN SFRCS CORRECTED 1

1 T=7 AUXILIARY FEEDWATER VALVES FAIL TO RE-0 PEN i

e N .

i s .

A '

I D.

1 1

P M

. U P .

D E

E F

P

. U -

T R ,

A T

S E  ; . e K

A E M C

I O V T R

E M S O O

O R I T D L E S O U P R N S M T I E u N T  : V P O N O L C O T A R C V E T

( D T F E R A E N H E W L T C T D N T A E R E A W D F E O S

V P E S E I I E Y V F D F R R E O A E C S Y I P I E R R L U V C O A I S R N T I X E E A L U T S U R I A F E X I R Q E H O E P U S O A R S F O

T N T T E N E S N L E P E A B M O R T A P S L

- I I I - -

U - - S A Q S V .

E A A N

I M

9 9 0

T T h

kk I

.1 .

SE_001NCE OF_ EVEtlTS- (CONTINUEDl T = 12 3/fl AUXILIARY FEEDWATER ISOLATION VALVE FOR OTSG NO. 2 OPENE til N . OPERATORS T = lli BOTit STEAM GENERATORS " DRIED OUT" - EMERGENCY PROCEDURE INITI ATING MAKE UP/lllGit PRESSURE INJECTION COOLING .

i PRESSURIZER PILOT OPERATED REllEF VALVE (PORV) FAILS,TO CLOSE AFTER T= 16 1/l1 TillRD ACTUATION - PORV BLOCK VALVE CLOSEn 1/2 MINUTE LATER 8

!sd

_ SEQUENCE OF EVENTS (C0flTINUED)

T = 16 1/2 FL0w OBTAINED FROM STARTUP FEED PUMP TO OTSG NO. 1 MIN.

T = 18 1/2 FL0w OBTAINED FROM AUXILIARY FEED PUMP NO. 2 T = 18 1/2 PEAK REACTOR COOLANT TEMPERATURE 592*F (NORMAL 7 P0sT TRIP 550*F)

T= 19 3/fl Flow OBTAINED FROM AUXILIARY FEED PUMP NO. 1 ,

G 6

s '

A.

SILO _UDLC_li_0F _EynTS (CONTINULD)

T = 22 MIN. C00LDOWN OF IlEACTOR COOLANT SYSTEM FROM RAPID FEED OF STEAM GENERATORS T = 23 illGli PRESSURE INJECTION IN PIGGYBACK MODE TO MAINTAIN PRESSURIZER PRESSURE AND 1.EVEL .

I T = 23 MINIMUM REACTOR COOLANT SYSTEM PRESSURE 1716 PSIG (NORMAL PRESSURE 2150 PSic) ,

T = 29 PLANT ESSENTIALLY STABLE i .

k -

L

OPERATOR ACTIONS OUTSIDE CONTROL ROOM (CONTINUfD1 l

ST ARTUP FEEDWATER PUMP REQUIRED OPENING ll VALVES REQUIRED INSERTING FUSES IN BREAKER CONTROL CIRCUIT

• I AUXILIARY FEEDWATER REQUIRED OPENING ISOLATION VALVES REQUIRED RESETTING OF PUMP TURBINE TRIP THROTTLE VALVES ENCOUNTERED)

Nu -

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Jl i

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N

. Table 5.1 Summary of Equipment Troubleshooting Hesults HATURE OF COMP.ENIS FAILUHE PROBABLE ROOT CAUSE ITEM Control System Elect.ronic Circuit. Pre-existing Control System Overspeed Problems llave Not lleen Resolved

1. Hain feedwater Turbine Card Failure Troubleshooting Activities Spurious Actuation Not Ident.ified llave Not Yet Degun

2. Closure of MSIVs of SFRCS Steam Safeties, Atmos. Abnormal Pressure Not Identifled 3.

Vents Control Testing with Plant ilot. Needed Overspeed condensate Flow to Turbines From to Verify Cause

4. Aux. Feedwater Turbines Steam Supply Lines During Turbine Start. .

Improper Settings for Torque  ;

5. AfW Cont.ainment Isolation Would Not Re-open Switch Bypass Contacts Valves '

Failure could Hot De Reproduce (

Steam Supply Valve to Short Cycle Not Identified -

,Iinproper Torque Switch Bypass-6.

AFPI #1 ' Contacts Could De Probl'em Failure of One of Two Channels failed, Low Not. Ident.ffled Could Hot He Reproiluced

7. Source Range NI Cause May Never De Ident.1(ied Disassenhly of Valve and Testing P0ltV Did Not Close of Control System Failed to U.

Heveal Cause

• Did Not. " Reset" Indication Problem Only - -

9. S/U Feedwater Control Indicator Lamp Valve Not. a liardware Problem Hecovery of AFP Turbine Trip-lbrottle Valve I.ack of Operator Training

10. *

• Operational UIifi-

) ',

cult.ies .

N b l

T. N Table 5.1 Sununary of Equipment Troubleshooting Results (Continued) ilATURE OF COMMEllTS FAILURE PRODADLE ROOT CAUSE ITEM

11. AFP #1 Suction Transfer Transfer to Service tiot Identified Water Troubleshooting riot Reviewed Turbine Turning Gear Did not Engage by Team 12.

- Tr$ubleshooting flot Reviewed

13. Centrol Room IIVAC Spurious Transfer by Team to Emergency Mode Water llammer, Valve Mis- Assembly Cause of. Water llammer tiot Yet

14. Turbine Dypass Valve Structured Known e

S O

A

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