ML17241A411

LER 99-007-00:on 990610,unplanned Cooldown Transient Occurred Due to Personnel Error.Trained & Briefed Personnel & Revised Procedures.With 990716 Ltr

ML17241A411
Person / Time
Site:	Saint Lucie
Issue date:	07/16/1999
From:	Frehafer K, Stall J FLORIDA POWER & LIGHT CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
L-99-160, LER-99-007, LER-99-7, NUDOCS 9907210143
Download: ML17241A411 (7)

Text

CATEGORY 1 REGULATO INFORMATION DISTRIBUTION STEM (RIDS)

ACCESSION'NBR:9907210143 DOC.DATE: 99/07/16 NOTARIZED: NO DOCKET I FACIL:50-389 St. Lucie Plant, Unit 2, Florida Power & Light Co. 05000389 AUTH. NAME AUTHOR AFFILIATION FREHAFER,K.W. Florida Power S Light Co.

STALL,J.A. Florida Power 6 Light Co.

RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

LER 99-007-00:on 990610,cooldown transient during reactor startup was noted. Caused by personnel error. Trained 6 briefed personnel &. revised procedures. With 990716 ltr.

DI'STRIBUTION CODE: IE22T COPIES RECEIVED:LTR ENCL SIZE:

TITLE: 50.73/50.9 Licensee Event Report (LER), Incident Rpt, etc.

NOTES:

RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL LPD2-2 PD 1 1 GLEAVES,W 1 1 INTERNAL: ACRS 1 CWzzz,.E, CENTER 1 1 NRR/DIPM/IOLB 1 NRR /DRIP/REXB 1- 1 NRR/DSSA/SPLB 1 RES/DET/ERAB 1 1 RES/DRAA/OERAB 1 RGN2 ,FILE 01 1 1 EXTERNAL: L ST LOBBY WARD 1 1 LMITCO MARSHALL 1 1 NOAC POORE,W. 1 1 NOAC QUEENER,DS 1 1 NRC PDR 1 1 NUDOCS FULL TXT 1 1 D

N NOTE TO ALL "RIDS" RECIPIENTS:

PLEASE HELP US TO REDUCE WASTE. TO HAVE YOUR NAME OR ORGANIZATION REMOVED FROM DISTRIBUTION LISTS OR REDUCE THE NUMBER OF COPIES RECEIVED BY YOU OR YOUR ORGANIZATION, CONTACT THE DOCUMENT CONTROL DESK (DCD) ON EXTENSION 415-2083 N FULL TEXT CONVERSION REQUIRED TOTAL NUMBER OF COPIES REQUIRED: LTTR 16 ENCL 16

Fiorida Power 5 Light Company, 6351 S. Ocean Drive, Jensen Beach, FL 34957

'July 16, 1999 L-99-160 10 CFR $ 50.4 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re: St. Lucie Unit 2 Docket No. 50-389 Reportable Event: 1999-007-00 Date of Event: June 10, 1999 Personnel Error During Reactor Startu Led to Un lanned Cooldown Transient The attached voluntary Licensee Event Report 1999-007 is being submitted to provide notification of the subject event.

Very truly yours, J. A. Stall

, 'Vice President St. Lucie Nuclear Plant JAS/EJW/KWF Attachment cc: Regional Administrator, USNRC, Region H Senior Resident Inspector, USNRC, St. Lucie Nuclear Plant 9'rr072iOX4G 9'rr07i6 PDR ADQCK 05000389 S PDR an FPL Group company

RC FORM 366 U.S. NUC REGULATORY COMMISSION APPROVED BY NO. 3150-0104 EXPIRES 06/30/2001 (8-1 998)

Estimated burden per responso to comply with this mandatory information collection request: 50 hrs. Reported lessons learned are incorporated jnto the licensing process and fed back to Industry. Forvrard comments regarding LICENSEE EVENT REPORT (LER) burden estimate to the Records Management Branch (T-6 F33), U.S. Nuclear Regulatory Commission, Washington, DC 20555~01, and to the Paperwork Reduction Proiect (3t5th0104), Office of Management and Budget, (See reverse for required number of Washington, DC 20503. If an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, digits/characters for each block) and a person is not required to respond to, the information collection.

FACILITY NAME (1) DOCKET NUMBER (2) PAGE (3)

St. Lucie Unit 2 05000389 Page 1 of 5 TITLE (4)

Personnel Error During Reactor Startup Led to Unplanned Cooldown Transient EVENT DATE (5) LER NUMBER (6) REPORT DATE (7) OTHER FACILITIES INVOLVED (8)

SEQUENTIAL REVISION FACIUTY NAh'IE DOCKET NuhIBER MONTH DAY YEAR MONTH DAY YEAR NUMBER NUMBER FACIUTY NAME DOCKET NUMBER 06 10 1999 1999 - 007 - 00 07 16 1999 OPERATING THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR gt (Check one or moro) (11)

MODE (9) 20.2201 (b) 20.2203(a)(2) (v) 60.73(a) (2) (i) 60.73(a)(2) (viii)

POWER 20.2203(a)(1) 20.2203(a) (3)(i) 50.73(a)(2) (ii) 50.73 (o) (2) (x)

LEVEL (10) 000 20.2203(a) (2)(i) 20.2203 (a) (3) (ii) 50.73(a) (2) (iii) 73.71 20.2203(a)(2) (ii) 20.2203(a)(4) 50.73(a) (2)(iv) OTHER 20.2203 (a) (2) (iii) 50.36(c)(1) 50.73(a)(2) (v) Specify In Abstract below or 20.2203(a)(2)(iv) 60.36(c)(2) 50.73(a)(2) (vii) in NRC Form 380A LICENSEE CONTACT FOR THIS LER 12)

NAME TELEPHONE NUMBEIt (Include Ares Code)

Kenneth W. Erehafer, Licensing Engineer (561) 467 7748 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT 13 CAusE SYSTEM COMPONENT MANUFACTURER REPORTABLE REPORTABLE To EPIX CAUSE SYSTEM COMPONENT MANUFACTURER To EPIX SUPPLEMENTAL REPORT EXPECTED (14) MONTH DAY EXPECTED YES SUBMISSION (If yee, complete EXPECTED SUBMISSION DATE). X NO DATE (16)

ABSTRACT (Limit to 1400 spaces, i.e., approximate/y 15 sing/ewpaced typewritten /ines/ (16)

This voluntary LER describes an unplanned reactor plant: cooldown transient that occurred on June 10, 1999. At 0345 hours0.00399 days <br />0.0958 hours <br />5.704365e-4 weeks <br />1.312725e-4 months <br /> on June 10, 1999, Unit"2 was in Mode 3 at normal operating pressure and normal operating temperature. A reactor startup was in progress, but temporarily suspended to trouble shoot annunciator problems. Licensed control room personnel decided to perform post maintenance testing on the number 3

'throttle valve; an evolution that required latching the turbine.

At 0412 hours0.00477 days <br />0.114 hours <br />6.812169e-4 weeks <br />1.56766e-4 months <br />, the turbine was latched without incident. At approximately 0420 hours0.00486 days <br />0.117 hours <br />6.944444e-4 weeks <br />1.5981e-4 months <br />, the control room was informed that the testing was complete and that the turbine could be tripped. After the turbine was locally tripped, the main feedwater 15 percent bypass valves were checked, but erroneously not reset, because the controller output had not changed. At 0423 hours0.0049 days <br />0.118 hours <br />6.994048e-4 weeks <br />1.609515e-4 months <br />, several annunciators came in which indicated a steam generator overfeed condition including letdown low pressure, steam generator high levels, and pressurizer low level. At that time, the 15 percent valves were reset, the overfeed was terminated, and levels were restored to normal conditions.

This event was caused by the failure to use existing procedural guidance on turbine shutdown. Contributing factors include non-conservative reactivity management decisions, inadequate operator knowledge on the operation of the main feedwater 15 percent bypass valves, and an inadequate pre-evolution brief. Corrective actions include training, briefings, and procedure changes.

NRC FORM 360 I0.1998)

RC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (6- I 996)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION DOCKET FACILITY NAME (1) NUMBER (2) LER NUMBER (6) PAGE (3)

YEAR SEQUENTIAL REVISION NUMBER NUMBER St. Lucie Unit 2 05000389 Page 2 of 5 1999 007 - 00 TEXT (Ifmore spece is required, use eddidonel copies of /VRC Form 366A) (17]

Description of the Event At 0345 hours0.00399 days <br />0.0958 hours <br />5.704365e-4 weeks <br />1.312725e-4 months <br /> on June 10, 1999, Unit 2 was in Mode 3 at normal operating pressure and normal operating temperature (NOP/NOT). The main steam isolation valves (MSIVs)

[EIZS:SB:V] were open and vacuum existed in the main condenser. The steam bypass control system was maintaining reactor coolant 'system (RCS) [EIIS:AB] temperature in automatic control and the main feedwater system [EIIS:SJ] was in operation and maintaining steam generator [EZZS:SB:SG] levels automatically on the 15 percent bypass valves [EIIS:SJ:FCV]. The main turbine DEH system had xecently been returned to service following a repair to a leak on the number 3 turbi.ne throttle valve

[EZIS:TA:FCV]. A reactor staztup was in progress. The Unit 2 licensed control zoom staff consisted of the assistant nuclear plant supervisor (ANPS), board reactor control operator (RCO), desk RCO, a RCO dedicated to the startup, and a senior reactor operator (SRO) reactivity manager dedicated to the startup.

I At approximately 0345 hours0.00399 days <br />0.0958 hours <br />5.704365e-4 weeks <br />1.312725e-4 months <br /> the rotating maintenance shift supervisor (RMSS) and system engineer requested that Operations latch the turbine to post maintenance test (PMT) the work performed on the number 3 throttle valve. The ANPS discussed the possibility of delaying the PMT until the turbine startup with the RMSS. The ANPS decided to go ahead with the PMT in order to save time in case a rework on the valve was required. The nuclear plant supervisor (NPS) and reactivity manager were informed of the intention to latch the turbine. A tailboard was conducted for the turbine latch evolution by the ANPS with the board RCO and nuclear watch engineer (NWE). Procedure GOP-201, "Reactor Plant Startup Mode 2 to Mode 1," was used as guidance for the latching evolution. Tripping of the turbine aftez the PMT was not discussed in the brief.

At 0405 hours0.00469 days <br />0.113 hours <br />6.696429e-4 weeks <br />1.541025e-4 months <br />, annunciator P-17, the main steam isolation signal (MSZS) 2A S/G Pressure Low Channel Trip annunciator, alaxmed in the control room and then cleared.

Investigation found that the D channel MSIS block bistable on the engineered safety feature actuation signal (ESFAS) cabinet had also come in. The ANPS/NPS discussed the operability status of the effected channel and decided that since the reactor was still in Mode 3, to temporarily stop the startup. Maintenance personnel would perform a functional check on the affected steam generator pressure channel to ensure operability prior to entry into Mode 2. Control element assembly (CEA) banks A, B, 1, and 2 were fully withdrawn. CEA bank 3 was 57 inches withdrawn. CEA banks 4 and 5 were not withdrawn. The projected entry into -Mode 2 was the next rod withdrawal sequence.

At 0412 hours0.00477 days <br />0.114 hours <br />6.812169e-4 weeks <br />1.56766e-4 months <br />, the turbine was latched without incident. At approximately 0420 hours0.00486 days <br />0.117 hours <br />6.944444e-4 weeks <br />1.5981e-4 months <br />, the watch engineer called the control room and said that the PMT was completed and that the tuzbine could be tripped. The ANPS directed the watch engineer to trip the turbine locally. After the turbine was tripped, the board RCO checked the 15 percent bypass valves, but did not reset the valves because the controller outp'ut had not changed. The ANPS was informed that the contxoller output had not changed and the valves had not been re'set. The watch engineer was also informed that the 15 percent valves had not been reset when he entered the control room.

Shortly thereafter, the ANPS left the surveillance area to discuss the D channel steam'generator low pressure bistable troubleshooting status with, the Operations Manager. The board RCO left the vicinity of the feed station to investigate an annunciator. At 0423 hours0.0049 days <br />0.118 hours <br />6.994048e-4 weeks <br />1.609515e-4 months <br /> several annunciators came in which indicated a steam generator overfeed condition including letdown low pressure, steam generator high NRC FORM 300A (0.1998)

'4RC FORM 366A .S. NUCLEAR REGULATORY COMMISSION 6 i998)

LICENSEE EVENT REPORT (LERj TEXT CONTINUATION DOCKET FACILITY NAME (1) LER NUMBER (6) PAGE (3)

NUMBER (2 SEQUENTIAl REVISION NUMBER NUMBER St. Lucie Unit 2 05000389 007 Page 3 of 5 1999 00 TEXT (Ifmora space is required, use additional copies of NRC Form 366A/ (1 7)

Description of the Event (cont'd) levels, and pressurizer low level. At that time, the 15 percent valves were reset, the overfeed was terminated, and levels were restored to normal conditions. During the transient RCS temperature was reduced from 535'F to 526'F, or approximately 9'F.

Cause of the Event The cause of this event was that the operators did not utilize existing procedural guidance for turbine shutdown. There is no specific procedure to latch and trip the turbine for testing. The operators did use procedural guidance from GOP-201, "Reactor Plant Startup Mode 2 to Mode 1," to latch the turbine. However, tripping of the turbine was not discussed prior to the control room being informed that the PMT was completed. No procedural guidance for tripping the tu'rbine had been considered by the ANPS or board RCO. When notified the turbine was ready to be tripped, the ANPS made the decision to trip the turbine without considering what procedural guidance he was using to do the trip. NOP-2-0030125, "Turbine Shutdown Full Load to Zero Load," steps 7.41.3 7.41.6 provides the guidance for tripping the turbine and specifically addresses resetting the 15 percent bypass valves after tripping the turbine.

Contributing factors to this event were:

~ Conservative Decision-Making: The crew decided to proceed with turbine latch evolution with a reactor startup in progress.

n The ANPS considered the possibility of the adverse effects evolution caused the RCS to cooldown due to turbine valve mispositioning or leak if the turbine latch by. However, he considered this possibility remote and decided the PMT needed to be completed to ensure the turbine roll would not be delayed. The NPS considered the plant stable since the startup was on hold and did not have any problem with the turbine evolution proceeding. However, there was no valid reason to complete this evolution prior to completion of the reactor startup.

~ ..Pre-evolution briefing: The tailboard briefing for the evolution was not adequate.

The ANPS considered the turbine latch a minor evolution with direct procedural

'guidance and therefore, did not consider "Conduct of Operations," CS-9 checklist.

it necessary to use the AP 0010120, The brief did not include all members of the control staff, only the personnel involved in the evolution. The ANPS did not include the desk RCO because he was performing his normal shiftly duties and was behind due to the increased paperwork load of the startup. The ANPS did not include the reactor startup RCO or the reactivity manager because they were dedicated to only the startup. However, because of the possible reactivity effects of the evolution, the individuals involved in the startup should have been included in the brief.

Only the turbine latching evolution was discussed in the prejob brief. The ANPS was focused on ensuring the DEH computer was properly setup for the turbine latch and the proper turbine response on latching. GOP 201, "Reactor Plant Startup-Mode 2 to Mode 1," steps 6.25 6.33 were reviewed and considered appropriate for the evolution. Prior to and during the brief, the ANPS never considered tripping the turbine or the status of the 15 percent bypass valves post-trip.

NRC FOAM 300A (0.1998)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION 6-1 998l LICENSEE EVENT REPORT" (LERj TEXT CONTINUATION DQGKET FACILITY NAME (1) NUMBER (2) LER NUMBER (6) PAGE (3)

SEQUENTIAL REVISION NUMBER NUMBER St. Lucie Unit 2 05000389 007 Page 4 of 5 1999 00 TEXT Iifmore space is reriuired, use additional copies of IVRC &rm 366AJ (17)

Cause of the Event (cont'd)

Other members of the control room staff were aware of the post turbine trip status of the 15 percent bypass valves and the importance of resetting the valves. Had the brief included all members of the crew, it is likely someone would have discussed the importance of the promptly resetting the valves and of the procedural guidance to do so.

~ Operator Training/Knowledge Level: The operators misinterpreted the 15 percent bypass valve controller indication after the turbine trip.

The 15 percent bypass valves fail to the 5 percent flow position following a turbine trip. The reactor turbine generator board (RTGB) controller is taken out of the circuit but there is no change in controller output. The operators mistakenly interpreted the normal controller output following the trip as evidence that the valve was still functioning in automatic and that resetting.'he valves'as not necessary.

The three licensed operators involved in the evolution failed to re'cognize the status of 15 percent valves post turbine trip. They misinterpreted controller output not, changing as indication that the valve had not repositioned to the five percent flow position. Had any of the three operators recognized that the controller was out of the circuit, and that controller indica'tion remaining the same was an expected response when the valves had moved to the design post turbine trip position, then the valves would have been reset.

~ Self-Checking: The operators did not adequately follow up on an unexpected plant zesponse.

The operators expected to have to reset the 15 percent bypass valves, but did not follow up when the expected controller response was not obtained. They incorrectly reasoned that since they had tripped the turbine locally, the 15 percent valves did not need to be reset. Other plant parameters that would have confirmed the 15 percent. valve positions, such as steam generator levels, were not

..closely monitored to verify proper operation. The board RCO allowed himself tO become distracted and left to respond to another annunciator. Additionally, other

', .members of the control room staff were not brought into the discussion of the unexpected response of the 15 percent valves.

Analysis of the Event This event is being reported as a voluntary LER.

Analysis of Safety Significance FPL performed an assessment for this event using ABB-CE best estimate standard design calculations and determined that the inadvertent cooldown did not result in Mode 2 conditions. Calculationally, K,qg remained less than 0.99, but because of uncertainties in the calculations and in measurements, it is possible that the reactor entered Mode 2. However, the plant had a reactor,startup in progress and was ready to enter Mode 2.

The decision to perform the PMT on the number 3 throttle valve during a reactor startup was a nonconservative reactivity management decision. Reactivity management is a primary function of the licensed operators in the control room and this decision NBC FORM 3BBA IB-1998)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION 6-1998)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION DOCKET PAGE (3)

FACILiTY NAME (1) NUMBER (2) LER NUMBER (6)

SEQUENTIAL REVISION NUMBER NUMBER St. Lucie Unit 2 05000389 007 Page 5 of 5 1999 00 TEXT (Ifmore spaceis required, use additional copies of NRC Farm 366A) (17)

Analysis of Safety Significance (cont')

demonstrates a lack of sensitivity to reactivity management issues. Although this.

event most probably did not result'in an inadvertent mode change, this event did reveal several failed barriers that should have precluded the cooldown event. The enhancements to these failed barriers are addressed in the corrective actions noted below.

Corrective Actions

1. The SRO involved was temporarily removed 'from licensed activities in order to develop the root cause and corrective actions for this event. The SRO was returned to licensed duties after de-briefing the Plant General Manager on the findings.

2. Each available Operations department supervisor has signed a letter Acknowledging the requirements for AP 0010120, "Conduct of Operations," check sheet 9 fox prejob briefings and the requirements for procedure usage (with the balance due when the personnel return fzom vacations, etc.).

3. Procedure NOP-1/2-0030122, "Reactor Staxtup," is, being changed to include steps and cautions to not perform any evolution which could influence RCS temperature and thus reactivity during the approach to criticality,

4. Operations management has briefed all operations control room crews on the incident. The briefing stressed a) the importance of thorough p'rejob briefings using procedure AP 0010120, "Conduct of Operations," check sheet '9; b) the necessity of using the appropriate procedure for every evolution and every part, of every evolution; c) the importance of self-checking and following up on unexpected plant responses by use of diverse indications to ensure equipment status, and; d) the importance of conservative reactivity management during xeactor startup.

5. A Training Brief on operation of the 15 percent bypass valves is being issued to ensure all licensed operators know the operation and RTGB indications of the

..valves after a turbine trip.

6.'peration of shutdown/low power feed water control is being incorporated into the

'Licensed Operator Continuing Traini.ng Program to ensure all operators are aware of the operating characteristics and RTGB indications of feed system.

7. This event, including the root cause analysis, is being covered in Licensed Operator Continuing Training.

8. A video of proper prejob briefing techniques and expectations is being produced for use in Licensed Operator Continuing Training.

Additional Information Failed Com onents Identified None Similar Events None NRC FORM 3BBA IB-1998)