ML17353A634

Rev 0 to JPN-PTN-SEFJ-96-015, Control Rod Operability Evaluation as Result of Incomplete Rod Insertion at Other Westinghouse Plants.

ML17353A634
Person / Time
Site:	Turkey Point
Issue date:	03/31/1996
From:	NUCLEAR FUEL SERVICES, INC.
To:
Shared Package
ML17353A633	List: ML17353A632 ML17353A634
References
JPN-PTN-SEFJ-96, JPN-PTN-SEFJ-96-015, JPN-PTN-SEFJ-96-15, NUDOCS 9604110102
Download: ML17353A634 (38)

Text

JPN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 1 of 14 PAGE 6 OF 23 PLORXDA POWER Ec LIGHT CO.

Turkey Point Units 3 & 4 Operability Evaluation Control Rod Operability Evaluation as a Result of Incomplete Rod Insertion at Other Westinghouse Plants JPN-PTN-SEFJ-96-015 Rev 0 March 1996 Safety Related Nuclear Fuel Nuclear Technical Services 9604ll0102 960405 05000250 PDR ADQCK I PDR

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JPN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 2 of 14 PAGE 7 OF 23 REVIEW AND APPROVAL RECORD PLANT Turke Point UNIT 3 & 4 TITLE Control Rod erabilit Evaluation as a Result of Znco lete Rod Insertion at Other Westin house Plants LEAD DISCIPLINE Nuclear Fuel ENGINEERING ORGANISATION Nuclear Technical Services REVIEW/APPROVALI INTERPACE TYPE GROUP PREPARED VERIPIED APPROVED PPL APPROVED>>

INPUT REVIEW NIA MECH ICC CIVIL NUC" CSI NUC PUEL x

~ Por Contractor Evals As Dotormlnod By Projocts *~ Rovlow Intorfaco As A Mln On All IOCPR50.59 Evals and PLAs FPL PROJECTS APPROVAL: Ori inal si ed b Mana er Nuclear Fuel DATE: 3-12-96 OTHER INTERFACES

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~ JPN-PTN-SEFJ-96-015 L-96-082 gevision 0 ATTACHMENT Page 3 of 14 PAGE 8 OF 23 Control Rod Operability Evaluation as a Result of Incomplete Rod Insertion at Other Westinghouse Plants TABLE OF CONTENTS Section Pa e Number

1.0 Background

2.0 Description and Purpose 3.0 Licensing Requirements 4.0 Evaluation 5.0 Safety'Analysis 12 6.0 Conclusions 7.0 References 14

JPN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 4 of 14 PAGE 9 OF 23 1.0 Back round Between December 1995 and February 1996, three events involving stuck rod cluster control assemblies (RCCAs) occurred in Westinghouse Plants'his prompted the NRC to issue NRC Bulletin 96-01 (Reference 7.1) which addresses incomplete RCCA insertion.

1.1 South Texas Pro'ect On December 18, 1995, South Texas Unit 1 experienced a turbine trip and a reactor trip from 100% Rated Thermal Power. While verifying control rod insertion, operators noted that the rod bottom lights of three control rod assemblies did not indicate full insertion; the digital rod position indication for each rod indicated six steps withdrawn. A step is equivalent to 1.59 cm [5/8 inch], and the top of the dashpot begins at 38 steps. One rod did drift into the fully inserted rod bottom position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, and the other two rods were manually inserted later. During subsequent testing of all control rods in the affected banks, the rod position indication for the same three locations, as well as a new location, indicated six steps withdrawn. As compared to prior rod drop testing, no significant differences in rod drop times were noted before reaching the upper dashpot area for any of the control rods.

Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after the rod drop tests, two of the rods drifted to the rod bottom position and the other two were manually inserted. All four control rods were located in 17X17 XLR fuel assemblies that were in their third cycle, with burnup greater than 42,880 megawatt days per metric ton uranium (MWD/MTU).

1.2 Wolf Creek Plant On January 30, 1996, after a manual scram from 80 percent power, five control rod assemblies at the Wolf Creek plant failed to insert fully. Two rods remained at 6 steps withdrawn, two at 12 steps, and one at 18 steps. At Wolf Creek, a step is equivalent to 1.59 cm [5/8 inch] and the top of the dashpot begins at approximately 30 steps. Three of the affected rods drifted to fully inserted within 20 minutes, one within 60 minutes, and the last one within 78 minutes. The results also indicate that there was some slowing down of affected rods before they reached the dashpot. After the scram, the licensee initiated emergency boration because all rods did not insert fully. During subsequent cold rod drop tests, the same five rods, plus an additional three rods, failed to fully insert. All of the affected rods were in 17x17 VANTAGE SH fuel assemblies, with burnup greater than 47,600 MWD/MTU.

'PN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 5 of 14 PAGE 10 OF 23 1.3 North Anna Plant On February 21, 1996, during the insert shuffle in preparation for loading North Anna 1, Cycle 12, two new control rod assemblies could not be removed with normal operation of the handling tool from the fuel assemblies in the spent fuel pool in which they were temporarily stored. The control rod assemblies were removed using the rod assembly handling tool in conjunction with the bridge crane hoist. The two affected fuel assemblies were 17X17 VANTAGE 5H assemblies, which had achieved 47,782 MWD/MTU and 49,613 MWD/MTU burnup during two cycles of irradiation.

2.0 Descri tion and Pu ose In Reference 7.1, the NRC requested that utilities "promptly determine the continued operability of control rods based on current information". This operability evaluation is intended to fulfillthis requirement.

3.0 Licensin Re irements The following provides the applicable licensing requirements for incomplete RCCA insertion.

3.1 Technical Specifications 3.1.1.1 requires that the shutdown margin be greater than or equal to 1.77 '.hp at End of Cycle (EOC) .

3.2 Technical Specifica'tions 3.1.3.1 requires that all full length rods shall be operable and positioned within + 12 steps of the group step counter demand position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after rod motion.

3.3 Technical Specifications 3.1.3.4 requires that the individual full length rod dropor time from the fully withdrawn position shall be less than equal to 2.4 seconds from beginning of decay of stationary gripper coil voltage to dashpot entry.

JPN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 6 of 14 PAGE 11 OF 23 4.0 Evaluation Based on a review of Reference 7.1, the following conclusions are drawn:

a. The phenomena is associated with fuel assemblies having high exposures (> 40,000 MWD/MTU) and core locations where RCCAs reside.

b. The phenomena is so far isolated to 17X17 Westinghouse fuel assemblies. There has been no indication that this phenomena affects the Westinghouse 15X15 fuel assemblies used at Turkey Point.

Table 4.1 provides the fuel assembly exposures for Unit 3 Cycle 15, Unit 4 Cycle 15 and Unit 4 Cycle 16 in the core locations where the RCCAs reside.

4.1 Unit 3 cle 15 Based on Table 4.1, Unit 3 Cycle 15 does not currently have any fuel assembly with exposure greater than 40,000 MWD/MTU residing in RCCA locations. The Unit tripped from 60% power on 2/9/96 (cycle burnup of approximately 3600 MWD/MTU) with all RCCAs fully inserting into the core.

'I At EOC 15, Unit 3 is projected to have 13 RCCAs that will reside in fuel assemblies with exposures greater than 40,000 MWD/MTU. These include the center RCCA in CBD, 4 RCCAs in SBB and 8 RCCAs in CBC.

4.2 Unit 4 C cle 15 Unit 4 Cycle 15 is in a refueling outage with all RCCA fully inserted. At the EOC, the Unit had 21 RCCAs residing in fuel assemblies with exposures greater than 40,000 MWD/MTU. These included 4 RCCAs in SBB, 8 RCCAs in CBA, 8 RCCAs in CBC and the center RCCA in CBD with a fuel assembly exposure of approximately 50,800 MWD/MTU. During the shutdown sequence on 3/4/96, plant management instructed the operators to perform a trip test of the RCCAs. The test was performed with CBD at 74 steps withdrawn, CBC at 202 steps withdrawn and the remaining of the RCCAs, fully withdrawn. The results of the test indicated that all RCCAs fully inserted.

JPN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 7 of 14 PAGE 12 OF 23 4.3 Unit 4 C cle 16 After the refueling outage, Unit 4 Cycle 16 will initially operate with no RCCA residing in high exposure fuel assembly locations. At the EOC only 5 RCCAs are projected to reside in fuel assemblies with exposures greater than 40,000 MWD/MTU.

These include 4 RCCAs in SBB and the center RCCA in CBD with assembly exposure of 50,100 MWD/MTU.

For Turkey Point, the top of the dashpot is located approximately 24" from the top of the bottom nozzle (Reference 7.2). Based on Reference 7.3, this distance corresponds to approximately 28 steps withdrawn. Reference 7.3 determined, assuming that all RCCAs residing in fuel assemblies with exposures greater than 40,000 MWD/MTU get stuck at 28 steps withdrawn (200 steps inserted), the impact on EOL shutdown margin is less than 100 pcm for Unit 3 Cycle 15 and Unit 4 Cycle 16. A reduction of 100 pcm is reasonable because both Units have 6" natural uranium blankets at the bottom of the fuel rods. In addition, at HZP the axial power shape is top peaked resulting in minimum worth of the RCCAs in the bottom of the core.

Using this result and the shutdown margin results from References 7.4 and 7.5, Table 4.2 was developed. Table 4.2 indicates that the Technical Specifications shutdown margin is maintained even after conservatively assuming that RCCAs residing in fuel assemblies with exposures greater than 40,000 MWD/MTU remained 28 steps withdrawn.

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.JPN-PTN-SEF J-96-01 5 TABLE 4.1 L-96482 REVISION 0 ATTACHMENT PAGE 8 OF 14 Page 13 of 23 Turkey Point Unit 3 Cycle 15 Current Bumup at Bumup Projected EOC Last Scram Typo of (as of 3/10/96) 8urnup (2/9/96)

Core Location Rod Bank Fuel MWD/MTU MWD/MTU MWD/MTU Observations E45 SBB OFA/DRFA 23,330 37,500 22,500 Full Insertion L45 SBB OFA/DRFA 23,330 37,500 22,500 Full Insertion L-11 SBB OFA/DRFA 23,330 37,500 22,500 Full Insertion E-11 SBB OFA/DRFA 23,330 37,500 22,500 Full Insertion F48 SBB OFA/DRFA 35,300 46,900 34,600 Full Insertion H46 SBB OFA/DRFA 35,300 46,900 34,600 Full Insertion K48 SBB OFA/DRFA 35,300 46,900 34,600 Full Insertion H-10 SBB OFNDRFA 35,300 46,900 34,600 Full Insertion C47 SBA OFNDRFA 20,800 34,000 20,000 Full Insertion G-03 SBA OFA/DRFA 20,800 34,000 20,000 Full Insertion J-03 SBA OFA/DRFA 20,800 34,000 20,000 Full Insertion N47 SBA OFNDRFA 20,800 34,000 20,000 Full Insertion N-09 SBA OFA/DRFA 20,800 34,000 20,000 Full Insertion J-13 SBA OFA/DRFA 20,800 34,000 20,000 Full Insertion G-13 SBA OFA/DRFA 20,800 34,000 20,000 Full Insertion C49 SBA OFNDRFA 20,800 34,000 20,000 Fulllnsertion E47 CBA OFA/DRFA 23,600 37,400 22,900 Full Insertion G45 CBA OFA/DRFA 23,600 37,400 22,900 Full Insertion J-05 CBA OFA/DRFA 23,600 37,400 22,900 Full Insertion L47 CBA OFA/DRFA 23,600 37,400 22,900 Full Insertion L-09 CBA OFA/DRFA 23,600 37,400 22,900 Full Insertion J-11 CBA OFA/DRFA 23,600 37,400 22,900 Full Insertion G-11 CBA OFNDRFA 23,600 37,400 22,900 Full Insertion E49 CBA OFA/DRFA 23,600 37,400 22,900 Full Insertion B46 CBB OFA/DRFA 18,300 26,800 17,800 Full Insertion F42 CBB OFA/DRFA 18,300 26,800 17,800 Full Insertion K-02 CBB OFA/DRFA 18,300 26,800 17,800 Full Insertion P46 CBB OFA/DRFA 18,300 26,800 17,800 Full Insertion P-10 CBB OFA/DRFA 18,300 26,800 17,800 Full Insertion K-14 CBB OFNDRFA 18,300 26,800 17,800 Full Insertion F-14 CBB OFNDRFA 18,300 26,800 17,800 Full Insertion B-10 CBB OFA/DRFA 18,300 26,800 17,800 Full Insertion D46 CBC OFA/DRFA 30,700 43,100 30,000 Full Insertion F-04 CBC OFA/DRFA 30,700 43,100 30,000 Fuilinsertion K44 CBC OFNDRFA 30,700 43,100 30,000 FullInsertion M46 CBC OFNDRFA 30,700 43,100 30,000 Fulllnsertion M-10 CBC OFA/DRFA 30,700 43,100 30,000 Fulllnsertion K-12 CBC OFA/DRFA 30,700 43,100 30,M0 Fulllnsertion F-12 CBC OFA/DRFA 30,700 43,100 30,000 Fulllnsertion D-10 CBC OFNDRFA 30,700 43,100 30,000 Fulllnsertion D48 CBD OFA/DRFA 23,400 36,000 22,700 Full Insertion H44 CBD OFA/DRFA 23,400 36,000 22,700 Full Insertion M48 CBD OFNDRFA 23,400 36,000 22,700 Full Insertion H-12 CBD OFA/DRFA 23,400 36,000 22,700 Full Insertion H-08 CBD OFNDRFA 38,200 49,400 37,600 Full Insertion

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.JPN-PTIP-SEF J-96-01 5 TABLE 4.1 L-96482 REVISION 0 ATTACHMENT PAGE 9OF14 Page 14 of 23 Turkey Point Unit 4 Cycle 15 Current Bumup at Bumup Approximate EOC Trip Test Typo of (as of 3/10/96) Bumup (3/4/96)

Core Location Rod Bank Fuel MWD/MTU MWD/MTU MWD/MTU Observations E<5 SBB OFA/DRFA ln Refueling 43,800 43,800 Full Insertion L%5 SBB OFNDRFA In Refueling 43,800 43,800 Full Insertion L-11 SBB OFA/DRFA In Refueling 43,800 43,800 Full Insertion E-11 SBB OFNDRFA In Refueling 43,800 43,800 Full Insertion F-08 SBB OFNDRFA In Retueling 34,300 34,300 Full Insertion H46 SBB OFNDRFA In Refueling 34,300 34,300 Full Insertion K48 SBB OFNDRFA In Refueling 34,300 34,300 Full Insertion H-10 SBB OFA/DRFA In Refueling 34,300 34,300 Full Insertion C47 SBA OFNDRFA In Refueling 31,600 31,600 Fulllnsertion G43 SBA OFNDRFA In Refueling 31,600 31,600 Fulllnsertion J-03 SBA OFA/DRFA In Refueling 31,600 31,600 Fulllnsertion N47 SBA OFA/DRFA In Refueling 31,600 31,600 Fulllnsertion N49 SBA OFA/DRFA In Retueling 31,600 31,600 Fulllnsertion J-13 SBA OFA/DRFA In Refueling 31,600 31,600 Fulllnsertion G-13 SBA OFA/DRFA In Retueling 31,600 31,600 Fulllnsertion C49 SBA OFNDRFA In Retueling 31,600 31,600 Fulllnsertion II EW7 CBA OFA/DRFA In Refueling 42,000 42,000 Full Insertion G45 CBA OFA/DRFA In Retueling 42,000 42,000 Full Insertion J-05 CBA OFA/DRFA In Refueling 42,000 42,000 Full Insertion LZ7 CBA OFA/DRFA In Refueling 42,000 42,000 Full Insertion L%9 CBA OFA/DRFA In Retueling 42,000 42,000 Full Insertion J-11 CBA OFA/DRFA In Retueling 42,000 42,000 Full Insertion G-11 CBA OFA/DRFA In Refueling 42,000 42,000 Fulllnsertlon E-09 CBA OFNDRFA In Retueling 42,000 42,000 FullInsertion B46 CBB OFA/DRFA In Retueling 26,000 26,000 Full Insertion F%2 CBB OFNDRFA In Retueling 26,000 26,000 Fulllnsertion K%2 CBB OFA/DRFA In Retueling 26,000 26,000 Full Insertion P-06 CBB OFA/DRFA In Refueling 26,000 26,000 Full Insertion P-10 CBB OFA/DRFA In Refueling 26,000 26,000 Full Insertion K-14 CBB OFA/DRFA In Retueling 26,000 26,000 Full Insertion F-14 CBB OFNDRFA In Retueling 26,000 26,000 Fullinsertion B-10 CBB OFNDRFA In Refueling 26,000 26,000 Fulllnsertion D-06 CBC OFA/DRFA In Retueling 47,900 47,900 Full Insertion F44 CBC OFA/DRFA In Retueling 47,900 47,900 Fulllnsertion K-04 CBC OFA/DRFA In Retueling 47,900 47,900 Fulllnsertion M-06 CBC OFNDRFA In Retueling 47,900 47,900 Fulllnsertion M-10 CBC OFNDRFA In Refueling 47,900 47,900 Fulllnsertion K-12 CBC OFA/DRFA In Retueling 47,900 47,900 Fulllnsertion F-12 CBC OFNDRFA In Retueling 47,900 47,900 Fulllnsertion D-10 CBC OFA/DRFA In Retueling 47,900 47,900 Fulllnsertion D%8 CBO OFA/DRFA In Refueling 34,000 34,000 Fulltnsertion H44 CBD OFA/DRFA In Refueling 34,000 34,000 Fulllnsertion M-08 CBD OFNDRFA In Retueling 34,000 34,000 Fulllnsertion H-12 CBD OFNDRFA In Retueling 34,000 34,000 Fulllnsertion H-08 CBO , OFA In Refueling 50,800 50,800 Fulllnsertion

.JPN-PTA-SEF J-96-015 TABLE 4.1 L-96482 REVISION 0 ATTACHMENT PAGE 10 OF 14 Page 15 of 23 Turkey Point Unit 4 Cycle 16 Bumup Projected EOC Bumup at Type of at BOC Bumup Last Scram Core Location Rod Bank Fuel MWD/MTU MWD/MTU MWD/MTU Obsenratlons E45 SBB OFA/DRFA 30,400 46,600 N/A N/A L-05 SBB OFNDRFA 30,400 46,600 N/A N/A L-11 SBB OFA/DRFA 30,400 46,600 N/A N/A E-11 SBB OFA/DRFA 30,400 46,600 N/A N/A F48 SBB OFA/DRFA 18,100 38,000 N/A NA H46 SBB OFA/DRFA 18,100 38,000 N/A N/A K48 SBB OFA/DRFA 18,100 38,000 N/A N/A H-10 SBB OFA/DRFA 18,100 38,000 N/A N/A C47 SBA OFA/DRFA 15,500 34,500 N/A N/A G43 SBA OFA/DRFA 15,500 34,500 N/A N/A J-03 SBA OFA/DRFA 15,500 34,500 N/A N/A N47 SBA OFA/DRFA 15,500 34,500 N/A N/A N49 SBA OFA/DRFA 15,500 34,500 N/A N/A J-13 SBA OFA/DRFA 15,500 34,500 N/A NA G-13 SBA OFA/DRFA 15,500 34,500 N/A N/A C-09 SBA OFA/DRFA 15,500 34,500 N/A N/A E47 CBA OFNDRFA 18,100 37,400 N/A N/A G45 CBA OFA/DRFA 18,100 37,400 N/A N/A J-05 CBA OFA/DRFA 18,100 37,400 NIA N/A L47 CBA OFA/DRFA 18,100 37,400 N/A N/A L49 CBA OFNDRFA 18,100 37,400 N/A, N/A J-11 CBA OFA/DRFA 18,100 37,400 N/A N/A G-11 CBA OFNDRFA 18,100 37,400 N/A N/A E49 CBA OFA/DRFA 18,100 37,400 N/A N/A B-06 CBB OFA/DRFA 17,600 29,100 N/A N/A F42 CBB OFA/DRFA 17,600 29,100 N/A NA K-02 CBB OFA/DRFA 17,600 29,100 N/A N/A P46 CBB OFNDRFA 17,600 29,100 N/A N/A P-10 CBB OFA/DRFA 17,600 29,100 N/A N/A K-14 CBB OFA/DRFA 17,600 29,100 N/A N/A F-14 CBB OFA/DRFA 17,600 29,100 N/A N/A B-10 CBB OFA/DRFA 17,600 29,100 N/A N/A D46 CBC OFA/DRFA 17,800 36,500 N/A N/A F44 CBC OFA/DRFA 17,800 36,500 N/A N/A K44 CBC OFA/DRFA 17,800 36,500 N/A N/A M46 CBC OFNDRFA 17,800 36,500 N/A N/A M-10 CBC OFNDRFA 17,800 36,500 N/A N/A K-12 CBC OFA/DRFA 17,800 36,500 N/A N/A F-12 CBC OFA/DRFA 17,800 36,500 N/A N/A D-10 CBC OFNDRFA 17,800 36,500 N/A N/A D48 CBD OFA/DRFA 18,100 36,600 N/A N/A H44 CBD OFA/DRFA 18,100 36,600 N/A N/A M48 CBD OFA/DRFA 18,100 36,600 N/A N/A H-12 CBD OFNDRFA 18,100 36,600 N/A N/A H48 CBD OFA/DRFA 34,500 50,100 N/A N/A OFA =15x15 Optimized Fuol Assembly DRFA = Debris Resistant Fuel Assembly (FPL Design)

JPN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 11 of 14 PAGE 16 OF 23 TABLE 4.2 SHUTDOWN REQUIREMENTS AND MARGINS Unit 3 Unit 4 Control Rod Worth '.b, C cle 15 EOL C cle 16 EOL All Rods Inserted Less 6.23 6.12 Worst Stuck Rod (1) Less 7'-. 5.79 5.69 Control Rod Re uirements Reactivity Defects (Doppler, Tavg Void, Redistribution) 2.78 2.75 Rod Insertion Allowance 0 '0 0.50 RCCAs Incomplete Insertion 0.10 0.10 (2) Total Requirements 3.38 3.35 Shutdown Mar in 1 - 2 2.41 2.34 Re uired Shutdown Mar in 1.77 1.77 Excess Shutdown Mar in 0.64 0.57

JPN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 12 of 14 PAGE 17 OF 23 5.0 Safet Anal sis In addition to shutdown margin, the impact on Safety Analysis needs to be considered.

5.1 Uncontrolled RCCA Withdrawal from Sub-critical A trip reactivity of 1.5~ hp is assumed in this analysis with the worst stuck rod assumed. The transient is not sensitive to small changes in trip reactivity since the transient is essentially turned around as a result of the Doppler defect.

5' Uncontrolled RCCA Withdrawal at Power A 4.0% bp is assumed in this analysis with trip reactivity ofassumed.'he the worst stuck rod transient is not sensitive to small changes in trip reactivity.

5.3 RCCA Misoperation (Dropped)

No impact.

5.4 CVCS Malfunction For a boron dilution event the reduction in rod worth can increase the required boron concentration. However, this event is limiting at BOC and not at EOC.

5.5 Feedwater System Malfunction A 4.0% bp is assumed in this analysis with trip reactivity ofassumed.

the worst stuck rod The transient is not sensitive to small changes in trip reactivity.

5.6 Excessive Increase in Secondary Steam Flow No impact.

'PN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 13 of 14 PAGE 18 OF 23 5.7 Partial / Complete Loss of Forced Reactor Coolant Flow A trip reactivity of 4.0~ hp is assumed in this analysis with the worst stuck rod assumed. The transient is not sensitive to small changes in trip reactivity.

5.8 Locked Rotor A trip reactivity of 4.0% hp is assumed in this analysis with the worst stuck rod assumed. The transient is not sensitive to small changes in trip reactivity.

5.9 Loss of Load and/or Turbine Trip A trip reactivity of 4.0% hp is assumed in this analysis with the worst stuck rod assumed. The transient is not sensitive to small changes in trip reactivity.

5.10 Loss of Normal Feedwater Flow A trip reactivity of 4.0% hp is assumed in this analysis with the worst stuck rod assumed. The transient is not sensitive to small changes in trip reactivity.

5.11 Rupture of Steam Pipe The most important parameter is the assumed 1.77~hp shutdown margin and as discussed in Section 4.0. This margin is not challenged by the postulated reduction in rod worth.

5.12 RCCA Ejection The transient assumed a worst stuck rod for trip reactivity.

The transient is not sensitive to small changes in trip reactivity since the transient is essentially turned around as a result of the Doppler defect.

5.13 Large and Small LOCAs No impact since no credit is taken for RCCAs.

JPN-PTN-SEFJ-96-015 L-96-082 Revision 0 ATTACHMENT Page 14 of 14 PAGE 19 OF 23 6.0 Conclusions Based on the previous analysis, the following conclusions can be drawn.

6.1 The impact of the uninserted worth on shutdown margin is small

(< 100 pcm) .

6. 2 Shutdown margin continues to be met in the event that the RCCAs residing in fuel assemblies with exposures greater than 40,000 MWD/MTU only reached 28 steps withdrawn (200 steps inserted) rather than fully inserted. This is applicable to Unit 3 Cycle 15 and Unit 4 Cycle 16.

6.3 A RCCA trip test performed at the EOC for Unit 4 Cycle 15 showed no indication of incomplete rod insertion. For this cycle, there were 21 RCCAs residing in fuel assemblies with exposures greater than 40,000 MWD/MTU. Worth noting is that the center RCCA resided in a fuel assembly with 50,800 MWD/MTU at the time of the trip test. This seem to indicate that the phenomena experienced in 17X17 Westinghouse fuel assemblies is not manifested in 15X15 fuel assemblies. It is judged that the results of this test are applicable to Unit 3 Cycle 15 due to the identical fuel designs (see Table 4.1).

6.4 The current safety analyses will remain valid for the kinds of trip scenarios that could be postulated to occur.

In summary, the RCCAs remain operable and continued operation is acceptable.

7.0 References 7.1 NRC Bulletin 96-01, "Control Rod Insertion Problems," March 8, 1996.

7.2 Westinghouse Drawing 2D32938, "Zircaloy Single, Dashpot Guide Thimble Tube," Revision 29.

7.3 JPN Calculation PTN-BFJF-96-066, "Shutdown Margin Assessment with IncompleteRod Insertion," Revision 0, Approved 3/12/96.

7.4 PC/M 94-134, "Turkey Point Unit 3 Cycle 15 Reload," Revision 1.

7.5 PC/M 95-066, "Turkey Point Unit 4 Cycle 16 Reload," Revision 2.

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FLOI A POWER AND LIGHT CO ANY TURKEY POINT NUCLEAR UNIT 3, CYCLE 15 L-96-082 ATTACHMENT PAGE 20 OF 23 FIGURE 1: CORE CONFIGURATION 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 EEOS EE08 EE I 5 NF4N HF~ NF 14 EE41 FF31 GG38 FF21 GG40 F F30 EE14 L4)

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15 14 13 10 FIGURE 1 RR35 RA13, RA40 HF01 HF10 HF11 TURKEY POINT NUCLEAR UNIT 4 CYCLE 15 SS29 TT42 UU46 UU33 UU48 TT41 SS41 CORE LOADING R61 R78 SS25 UU26 UU38 TT47 SS12 TT52 UU40 UU28 SS24 20P42WZ R64 R73 20P4IWZ SS23 TT22 UU03 SS09 TT09 TT20 TTt 0 8810 UUOS SS22 12P328WZ R59 R88 R77 12P330WZ S 832 UU29 UU10 SS45 UU16 SS35 UU17 SS33 UU02 SS48 UU20 UU30 SS44 12P332WZ RSS 20P35WZ R65 20P36WZ R75 20P26WZ R81 12P335WZ TT44 UU41 S SOS UU04 TT38 TT03 TT23 TT08 TT35 UU13 SSOS UU42 TT39 R51 20 PISWZ R55 20P27WZ R69 20P32WZ R88 20P46WZ RQI AA33 UU49 TTI5 TT14 SS38 TT16 TT29 UU21 TT25 TTOI SS37 TTOS TT51 UU50 RR39 HF02 R52 R68 20P37WZ R82 R89 HF20 RR03 UU34 SS03 TT21 UU14 TT26 UU22 AA05 UU23 TT31 UU11 TT30 SS13 UU35 AAOI HF05 R54 20P33WZ R60 20P38WZ R70 20P39WZ R78 20P30WZ R87 HF15 RR38 UU51 TT50 TT07 SS30 TT18 UU24 TT19 TT12 SS43 TT05 UU45 RR37 HF13 R109 RSI 20PIOWZ R83 HF07 TT38 UU43 S 801 UU12 TT34 TT01 TT24 TT13 UU07 SS07 UU37 TT40 R53 20P47WZ R56 20P31WZ R71 20P29WZ R88 20PI1WZ A92 SS40 UU31 UU09 SS47 UUOI SS42 UU15 SS38 UUOS SS48 UU05 UU25 SS39 12P331WZ R57 20P25WZ R101 20P34WZ R93 20P28WZ R85 12P329WZ SS20 TT32 UU19 SS15 TTI5 TT27 TT02 SS02 UU18 TT17 SS18 0 12P334WZ R82 R72 R79 12P333WZ SS26 UU32 UU44 TT48 SS16 TTIS UU39 UU27 SS21 Key: 20PISWZ R67 R74 20P43WZ 'd RRPP Reload Cycle 12 SSf 0 Reload Cycle 13 TT37 UU52 UU36 UUI7 Q TTIr 4r Reload Cycle 14 SS31 R63 TT43 R80 SS34 LMEND:

ta y UUfIr Feed Cycle 15 r RIP Control Rod RR36 RR07 RA34 ASSEM8LY ID. O&

HFP 0 Hafnium Insert HF06 HF16 HF23 INSERTS OX+

%Z PPPPPIWZ Waba Ineert WQ r

b3 g (4 Q C) h3

N 0 C

~ ~

ATTACHMENT7 L-96-082 (Page 1 of 1) ATTACHMENT PAGE 22 OF 23 REACTOR FUEL LOCATION DIAGRAM TURKEY POINT UNIT NO.~

CYCLE NO. 1(o 15 . 14 13 12 11 10 9 8 7 6 5 4 3 2 1 TT15 TT11 TT02 HF23 HF1 0 HFOO UU42 VV39 UU34 VU41 TT23 A70 TT45 W4d WSS UUSl VV01 VV45 W50 W38 N 1 dPO 77 1 dP05 10P03 TT47 W03 WOS UU1 0 VU31 UV04 UU25 W20 W10 VV10 1 2P357VR 73 R59 12P359WZ TT20 WSS W17 TT 17 W02 UV17 W2'1 UV22 W20 TT32 W40 TT25 1 2P305VRB 12P353VR 75 12P30 SVRSS 12P36 7VROS 12P354WZ W50 W03 W13 TT43 Wld UV10 W28 TT38 W14 VVOS VV51 UU39 R09 1 dP5 0 12P302WZ BP225 0 BP22 12P3d3VRd 10PSSW219 TTOS W47 W28 W24 W29 TT40 W34 TT37 W3S UU11 VV20 VV48 TT14 HF07 A74 BP22 BP233 SP234 8 HF13 TT27 VU3d W62 UU01 W22 UV12 W25 TT13 W30 VU13 W23 VV02 VV03 UV33 TT20 HF15 10PO 3 12P309 VR72 BP224 SP235% 11P370VRS 10PO HF05 W43 UV47 UV27 UV14 VV17 TT41 W32 W33 W1 1 W31 W52 W4S TT07 HF20 RBS SP220 SP23'I BP23 A101 HF02 VU38 W37 VU19 Wl 1 TT39 VV30 VVOO W31 TT42 W12 Wl 8 VVS4 UU40 A71 10P5 1 2P350WZ SP229VfRO 3 SP23 12P361VRO 1 dP01 7 TT18 VV42 W07 TT28 VV09 UU2 3 W24 VU15 W01 TT1 1 W15 Wi1 TT31 12P350 VR87 12P358VRS 3 11P371VRS 11P352VR84 12P304WZ TT48 WOO W05 W09 UU29 UU07 W19 VV18 TTid 12P355 VR75 AOB R70 12P300WZ ITSO W58 W57 VU49 VV04 UUSO W53 WOO TT49 10P04 4 ldPOS 10PO TT24 VU37 VV52 UV35 W49 UU43 TT19 B

TT09 TT30 TT10 HF11 HF10 HF01

~IAOC/nn/bvc/ev

L-96-082 ATTACHMENT PAGE 23 OF 23 TURKEY POINT FUEL ASSEMBLY DESIGN Description Fuel Assembly Array/Design 15 x 15 Debris Resistant Fuel Assembly (Optimized Fuel Assembly)

Fuel Rod Material Zircaloy Spacer Grid Material Top and Bottom Grids: Inconel Intermediate Grids: Zircaloy Guide Thimble Material Zircaloy Guide Thimble Inside Diameter Above Dashpot - 0.499 in.

Below Dashpot - 0.455 in.

Length of the Dashpot - 23.245 in.

Length of Guide Thimbles 152.970 in.

l V

c" 8

Distri52.txt Distribution Sheet y~ S>PP 8&'riority:

Normal From: Geetha Raghavan Action Recipients: Copies:

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internet: smittw@inel.gov INEEL Marshall 1

1 'ot Not Found Found Not Found Total Copies: 20 Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 003687003

Subject:

Turkey Point Unit 4- Reportable Event: 2000-001-00, on January 24, 2000, Manual React or Trip due to Main Feedwater Flow Control Valve Cage Disengagement Page 1

Distri52.txt Sody:

Docket: 05000251, Notes: N/A Page 2

FEB 2 2 2000 L-2000-043 10 CFR 5 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re: Turkey Point Unit 4 Docket No. 50-251 Reportable Event: 2000-001-00 Date of Event: January 24, 2000 Manual Reactor Trip due to Main Feedwater Flow Control Valve Cage Disengagement The attached Licensee Event Report 2000-001 is being submitted pursuant to the requirements of 10 CFR g 50.73 to provide notification of the subject event.

Ifthere are any questions, please contact us.

Very truly yours, R. J. Hovey Vice President Turkey Point Nuclear Plant RJH/SM Attachment cc: Regional Administrator, USNRC, Region II Senior Resident Inspector, USNRC, Turkey Point Nuclear Plant HL gQQQ Q 7 0+0 an FPL Group company

- NRC FORINT 366 U.S. NU REGULATORY COMMISSION APPROVED B NO. 31504104 EXPIRES 06/3pf2001 (6-tS98)

Estimated burden per response to comply with this mandatory informs<<~

coliecdon request: 50 hrs. Reported lessons learned ere incorporated into

~

LICENSEE EVENT REPORT (LER) process snd fed back to indusby. Forward comments records ih'icensing burden estimate to the Records Management Branch (TA F33), U.S. gucie r (See reverse for required number of Regulatory Commission, Washington. DC 205554001. end to the Paperwork Reduction proiect (31~104). Ofrce of Management end Budget, digits/characters for each block) Washington, DC 20503. If an information collection does not display e currently valid OMB control number, the NRC may not conduct or sponsor end e person ls not required to rospond to, the information collection.

Turkey Point Unit 4 05000251 Page 1 of 7 Manual Reactor Trip due to Main Feedwater Flow Control Valve Cage Disengagement SEQUENTIAL REVISION MONTH DAY MONTH DAY YEAR YEAR NUMBER NUMBER 01 24 2000 2000 - 001 - 00 02 23 2000 OPERATING THIS REPORT IS SUBMITTED PURSUANT TO THE RE QUIREMENTS OF 10 CFR ti: (Che ck one or more) (11)

MODE (9) 20.2201(b) 20.2203(a)(2)(v) 50.73(a)(2)(i) 50.73(a)(2)(viii)

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

LEVEL (10) 95 20.2203(a)(3)(ii) 50.73(a)(2)(iii) 73.71 20.2203(a)(2)(i) f";.~fj'g lgl'ggttft'i'$P je'?ji 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 in NRC Form 386A 20.2203(a)(2)(iv) 50.36(c)(2) 50.73(a)(2)(vii)

LICENSEE CONTACT FOR THIS LER 12 NAME TELEPH N NUMB R(lnerudeAree e)

Stavroula Mihalakea, Licensing Engineer (305) 246 - 6454 REPORTABLE MANUFACTURER REPORTABLE CAUSE SYSTEM COMPONENT MANUFACTURER CAUSE SYSTEM COMPONENT TO EPIX TO EPIX SJ FCV C635 MONTH DAY YEAR EXPECTED YES SUBMISSION X NO DATE (15)

(II yes, complete EXPECTED SUBMISSION DATE).

ABSTRACT (Limitto 1400 spaces, i.e., approximately 15 single-spaced typewritten lines) (16)

At approximately 7:30 AM on January 24, 2000, FPL's Turkey Point Unit 4 reduced power to 95% to investigate main feedwater flow instabilities caused by the "A" Steam Generator (SG) Feedwater Flow Control Valve, FCV-4-478. At approximately 11:14 AM feedwater flow appeared to increase causing a SG level deviation. The Operators placed FCV-4-478 in manual operation. A preliminary determination of valve internal problems versus control problems resulted in the decision to shut down the Unit by performing a fast load reduction. At approximately 11:42 AM, the Reactor Control Operator (RCO) manually tripped the reactor due to difficultyin controlling SG levels. Allrods were fully inserted and all systems except Feedwater functioned as designed.

The immediate cause of the reactor trip was a manual action taken by the RCO in response to Main Feedwater flow instabilities. The underlying cause of the trip was a failure in FCV-4-478 valve internals. The valve cage had disengaged from the valve body web. The root cause of the failure of FCV-4-478 is inadequate change management in the 1980's when the practice of periodic replacement of the cage was stopped; specifically, FPL failed to require periodic re-torque of a re-used FCV cage.

FCV-4-478 was repaired. FPL established inspection controls to monitor for signs of valve degradation.

Cage torque willbe verified for all feedwater FCV at the next opportunity.

NRC FORM 388 (6-1998)

NRC FOR5ll 366A U.S. NUCLEAR REGULATORY COMMIggl (6-1998) ~10)(

LlCENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITYNAME (1) DOCKET LER NUMBER (6)

NUMBER (2) PAGE (3) yEAR SEQUENTIAL REVISION NUMBER NUMBER Turkey Point Unit 4 05000251 2000 - -

Page 2 of 7 001 00 TEXT (Ifmom space is mqljifed, use additionai copies of NRC Form 366A) (17)

Event Description On January 24, 2000, FPL's Turkey Point Unit 4 was operating at 100% power.

At approximately 6:00 AM, the Feedwater Flow Control Valve (FCV) [S J:fcv] to the "A"Steam Generator (SG)[AB:sg], FCV-4-478, was at 100% demand with SG level decreasing. The Reactor Control Operator (RCO) reduced SG blowdown [WI] and started the third condensate pump [KA:p] to recover SG level. As a result of a.conservative management decision to provide additional operating margin, the RCO commenced a load reduction to 95% power and an Event Response Team (ERT) was formed. The Unit reached 95% power successfully, and FCV-4-478 seemed to provide stable SG level control.

At approximately 11:14 AM, while the ERT was investigating the source of earlier flow instabilities, FCV-4-478 appeared to initiate another flow transient, causing flow instabilities in all SGs. The RCO placed FCV-4-478 in manual and stabilized levels in all SGs. However, FCV-4-478 indicated deteriorating flow control stability. A preliminary field determination of valve internal problems versus control loop problems resulted in the decision to reduce power by using OffNormal Operating Procedure 4-ONOP-100, Fast Load Reduction. At approximately 11:42 AM, the RCO manually tripped the reactor due to difficultyin controlling SG levels.

The manual reactor trip was initiated in Mode 1 at 95% power with automatic reactor coolant system (RCS) [AB] pressure control operational. All rods [AA:rod] were fully inserted and all systems other than Feedwater functioned as designed. The Main Turbine [TA] automatically tripped in response to the manual reactor trip. The SG "A"and "B" Feedwater flow control valves were taken to manual prior to the reactor trip in response to unstable level control. Following the reactor trip, a feedwater isolation signal was generated on reactor trip with low RCS average temperature of 554 degrees F, as expected. FCV-4-478 did not fully isolate for approximately 100 seconds, allowing approximately 10% of the nominal feedwater flow into the "A"SG. In accordance with 4-EOP-E-O, Reactor Trip or Safety Injection, the RCO closed the Feedwater Isolation Valve MOV-4-1407 [SJ:isv], and terminated the FCV leakage flow. All SG levels were restored to desired levels.

A walkdown was performed on the affected piping and components associated with valve FCV-4-478.

A Feedwater Flow Transmitter [JB:ft] tube associated with the SG "B" loop was broken offat the interface of the 3/8 inch port connector [JB:A,con] with a 3/4-inch x 3/8-inch adapter. The port connector failure likely occurred as a result of the nearby SG "A" piping deflections during FCV-4-478 flow instabilities. FPL found no further evidence of damage to any other major components (piping/supports). This was determined from the observation of no insulation damage, no bent or misaligned supports, and no evidence of excessive movement.

NRC FORM 366A (6-1998)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (8-1998)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION OOCKET LER NUMBER (6) PAGE (3)

FACILITYNAME (1) NUMBER(2)

SEQUENTIAL REVISION NUMBER NUMBER Turkey Point Unit 4 05000251 Page 3 of 7 2000 001 00 TEXT (Ifmore space is tequilo d, use additional copies of NRC Form 366A) (17)

Background

The Turkey Point Unit 4 Main Feedwater System consists of two SG feedwater pumps [S J:p], two high pressure feedwater heaters [S J:hx], the Feedwater FCVs and the controls associated with these components. Feedwater leaving the high pressure feedwater heaters splits into three feedwater headers, which supply feedwater to the three SGs. The Feedwater FCV, one for each SG, controls flow to each SG. Upstream of each FCV is a motor operated valve, which is the feedwater isolation valve. Normally the FCV controller will be in "Auto" with power between 15-100%. During plant operations, the FCV maintains a programmed level of water in the steam generator by controlling feedwater flow to the SG depending upon the steam flow demand and actual level in the SG.

On December 25, 1999, Operations discovered that with Unit 4 at 100% power, the demand for FCV-4-478 was between 98% and 100%, while the demand for the FCVs on the other two SGs was about 90%. A condition report was initiated to document a high demand condition identified for FCV-4-478.

Investigation was underway to determine the validity of the demand and to isolate the problem to either the control system or the valve. Review of maintenance and calibration records, field inspections, measurements of feedwater flow for all FCVs (for comparison purposes), and an examination of performance data had been completed without identifying any anomaly associated with FCV-4-478. Additional investigation was conducted for other potential flow restrictions, including feedwater isolation MOV and check valves, and for bypass flow paths or undocumented demand. No, problem was identified. However, the investigation confirmed that FCV-4-478 continued to adequately maintain SG levels at full power conditions.

On January 16, 2000, blowdown was increased in all Unit 4 SGs to correct SG chemistry due to increased sodium concentrations. When blowdown was increased to 60,000 Ibm/hr, a SG "A"level deviation alarm [SG:la] was received. Operations discovered that FCV-4-478 could not maintain level with blowdown at 60,000 lbm/hr. Although level was slowly decreasing, both Steam Flow and Feed Flow channels were matched and operating correctly. "A"SG level could be maintained at 50,000 ibm/hr. The investigation activities planned in response to the December 25, 1999 condition report were augmented based on this event. Feed pump performance was monitored and manual valve positions were verified. Preparation was underway for both a non-intrusive radiographic inspection of the valve internals and a performance test to evaluate FCV response to varying blowdown conditions.

On January 24, 2000 an instability in SG Feedwater flow occurred. FPL decided to conservatively reduce power to provide additional operating margin. An Event Response Team (ERT) was formed.

The initial ERT activities were underway when feedwater flow control stability deteriorated without a corresponding valve position change (indicative of internal problems), and significant vibration of the feedwater piping occurred. At 11:42 AM, Turkey Point Unit 4 was manually tripped from 95% power.

The stem position and the valve indicating lights indicated that FCV-4-478 did not fully close.

NRC FORM 366A (6.1996)

. NRC FORM 366A U.S. NUCLEAR REGULATORY COMMIS'()

(6-1998)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION DOCKET LER NUMBER (6) PAGe (3)

FACILITYNAME (1) NUMBER (2)

SEQUENTIAL REVISION NUMBER NUMBER Turkey Point Unit 4 05000251 Page 4 of 2000 001 00 TEXT (lfmore spaceis required, use additional copies of NRC Form 366A) (17)

Failure Analysis The problem originally identified for FCV-4-478 was one of high demand when compared with similar valves for the "B" and "C" SGs. Further examinations of the control functions and the actual valve position also validated the demand signal. A number of potential failure mechanisms were under investigation. However, prior to performing a non-intrusive internal examination, the valve began to exhibit extreme control instability, which then led to the Turkey Point Unit 4 manual reactor trip on January 24, 2000.

FCV-4-478 is a 12 inch Copes-Vulcan double web valve. The valve body has an upper and a lower set of threads. The valve cage threads into the web at these two locations. The valve plug rides in the cage.

When the valve cage is threaded into the web (at installation), it is held in place by torque alone.

When FCV-4-478 was disassembled, the cage was found loose in the web. The upper set of threads on the valve body web were destroyed. The lower set of threads were damaged.

FPL believes that the cage could have come loose from the web only by relaxation of the torque over time. Until the 1980's FPL's practice was to replace the valve plug and valve cage at each refueling outage. The new cage was thus torqued into place approximately every 18 months. Because the cage rarely showed wear, FPL changed its maintenance practice sometime in the 1980's (the exact time is unknown), and began replacing only the plug, leaving the cage in place unless it showed signs of wear.

FPL did not recognize that periodic re-torquing of the valve cage was necessary to correct torque relaxation. The last known torque of FCV-4-478 took place in 1986.

The root cause of the failure of FCV-4-478 is inadequate change management in the 1980's when the practice of periodic replacement of the cage was stopped.

The phenomenon of relaxation of a threaded fastener over time following application of an installation torque is not uncommon. In the case of flow control valve cages, the most probable cause for this relaxation is time in service and flow induced loading. For FCV-4-478, the condition of the lower threads may have aggravated this phenomenon. It was documented in 1986 that the cage thread engagement was degraded from original condition. Such degradation would reduce the stability of the cage, permitting greater influence from flow instability and perhaps accelerating the cage disengagement. An examination of the procedures and work packages documentation used to overhaul FCV-4-478 did not identify any requirement to verify the cage torque on a periodic basis. The most recent documented verification of the torque occurred in June 1986. It is likely that thirteen years of service, without re-torque of the cage and under constant hydraulic loading, is sufficient time for torque relaxation and cage disengagement.

NRG FORM 366A (6.1998)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSI()II (6-1996)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION DOCKET LER NUMBER (6) PAGE (3)

FACILITYNAME (1) NUMBER (2)

SEQUENTIAl REVISION NUMBER NUMBER Turkey Point Unit 4 05000251 Page 5 of 7 2000 001 00 TEXT (Ifmore space is required, use additional copies o1 NRC Form 366A) (17)

Other evidence of relaxation of installation torque is available within the work history at Turkey Point.

A work package and an Operating Experience Feedback report review identified two other recorded loose cages during routine valve inspection activities: FCV-3-478 in April 1992 and FCV-3-488 in February 1991. This phenomenon likely became applicable after changing the maintenance practices in the 1980s. Previously, the valve internals, including the cage and plug, were changed on a routine basis. The practice was changed since the cage seldom evidenced any degradation that would require replacement. The replacement of the cage was eliminated in the 1980s without changing the inspection requirements, since the potential for torque relaxation was not recognized.

Cause of the Event The immediate cause of the reactor trip was a manual action taken by the RCO in response to Main Feedwater flow instabilities. The underlying cause of the trip was a failure in FCV-4-478 valve internals. The valve cage had disengaged from the valve body web. The root cause of the disengagement of the cage in FCV-4-478 was the failure to recognize that reuse of the FCV cage should have been accompanied by torque rechecks whenever plug replacements were scheduled. This resulted in specifying inadequate maintenance activities in the inspection/overhaul procedure for the feedwater FCVs. Procedure O-PMM-074.10, Main Feedwater System Flow Control Valve Inspection, which is performed every 18 months on each FCV, permits a visual inspection of the cage to accept its condition. The visual inspection should have been augmented with verification that the cage remained properly torqued into the valve body web. Implementation of that change would have eliminated the potential for torque relaxation and the subsequent potential for flow instabilities to loosen the cage within the threaded body.

Safety Consequences and Safety Analysis Impact Disengagement of the valve cage does not impact the function of the FCV until the loose cage becomes a restriction on flow. Such a condition can be identified by the external symptoms of high valve demand and valve position. The other two Unit 4 SG FCVs were monitored as part of the investigation of FCV-4-478. Normal stroke was verified for valves FCV-4-488 and FCV-4-498 during this reactor trip outage. The available data confirms no operability concern exists for the Unit 3 SG FCVs: FCV-3-478, FCV-3-488, FCV-3-498, or for the other two Unit 4 SG FCVs: FCV-4-488, and FCV-4-498. There are no other systems at Turkey Point which have double web Copes-Vulcan FCVs.

Continued monitoring will ensure no operability concerns develop. Interim monitoring will ensure proper valve function until the next refueling outage when valve cage torque can be verified.

Permanent monitoring will continue to track valve performance to detect any deteriorating trends in FCV performance.

The manual reactor trip resulted in an automatic turbine trip. The trends of nuclear power, pressurizer pressure, pressurizer water volume, RCS average temperature, RCS inlet temperature, and SG pressure for this trip compared very conservatively to the trends in the Updated Final Safety Analysis Report (UFSAR).

NRC FORM 366A (6.1996)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (0-1098)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITYNAME (1) DOCKET LER NUMBER (6) PAGE (3)

NUMBER (2)

SEQUENTIAL REVISION NUMBER NUMBER Turkey Point Unit 4 05000251 Page 6 of 7 2000 001 00 TEXT (Ifmore space is tequl)ed, use additional copies of NRC Form 366A) (17)

Following the reactor trip, a feedwater isolation signal was generated on reactor trip with RCS average temperature of 554 degrees F. FCV-4-478 did not fully isolate, allowing approximately 10% of the nominal feedwater flow into the "A"SG for approximately 100 seconds (normally the valve closes in 20 seconds). In case of failure of the FCV, termination of feedwater flow to the SG can be accomplished by closing the feedwater isolation MOV, or by tripping the Main Feedwater pump. For this case, and in accordance with EOP E-O, the RCO closed the feedwater isolation valve, which also terminated the leakage flow. The potential impact on the Safety Analyses of the additional feedwater flow to the SG has been evaluated. The two UFSAR safety analyses directly impacted by feedwater malfunction are the Feedwater Malfunction Event and the Main Steamline Break (MSLB) Event.

The Feedwater Malfunction Event is assumed to result in excessive feedwater reaching one SG. The excessive feedwater flow increases the heat removal capability of the secondary system thus resulting in a primary system cooldown. The cooldown of the primary system will cause a power increase due to negative reactivity feedback. The current analysis assumes one feedwater FCV malfunctions resulting in a step increase to 200% of the nominal feedwater flow to one SG. The assumptions and results of the analysis in the UFSAR bound the conditions of the actual event, i.e., the total amount of feedwater added to the SG in the safety analysis is significantly greater than the amount of feedwater added as a result of the FCV malfunction. Therefore, the RCS cooldown predicted in the Safety Analysis for this event envelops the cooldown caused by the FCV malfunction.

The Main Steamline Break analysis results in an RCS depressurization, cooldown and corresponding reactivity addition initiated from hot standby conditions. The analysis assumes that the positive reactivity resulting from the Steamline Break could exceed the minimum plant shutdown margin. The analysis assumes that the faulted SG is conservatively supplied with twice the nominal feedwater the intact SG receiving the nominal feedwater flow. The results of the analysis (factoring in the flow,'ith malfunction of the FCV occurring in either the faulted or intact SGs) conclude that fuel cladding damage is not likely to occur since the 95/95 Departure from Nucleate Boiling (DNB) ratio limit is satisfied. Therefore, because the assumptions and results of the analyses in the UFSAR bound the conditions of the actual event, this event did not compromise the health and safety of plant personnel or the general public.

Corrective Actions

1. The cage for the SG "A"Main Feedwater Flow Control Valve, FCV-4-478, was repaired and properly secured, ensuring acceptable operation by implementing a temporary design change and modification. FPL and the vendor are evaluating the acceptability of the temporary repair as a permanent modification of FCV-4-478.

NRC FORM 386A (6.1998)

0 NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (6-1996)

LlCENSEE EVENT REPORT (LER)

TEXT CONTINUATION FACILITYNAME (1) DOCKET LER NUMBER (6) PAGE (3)

NUMBER (2)

YEAR SEQUENTIAL REVISION NUMBER NUMBER Turkey Point Unit 4 05000251 Page 7 of 7 2000 001 00 TEXT (Ifmore spaceis required, use additional copies of NRC Form 366A) (17)

FPL reviewed maintenance records for all six valves, which represents all of the valves of this design at Turkey Point Units 3 and 4. Records indicate that four of the valves had their valve cage torque inspected. No records of any inspection were found for the Unit 3 FCV-3-498.

Interim monitoring of all (total of six) Turkey Point Units 3 and 4 Main Feedwater FCVs demand will be used to identify unusual trends in demand, indicative of potential cage disengagement. FPL will monitor and record the demand position for each Feedwater FCV once per shift until each ur)it's next refueling outage when cage torque will be verified.

3. Permanent monitoring of the loose cage symptom willbe incorporated in the System Engineer trends for the Feedwater system by trending valve position on a monthly basis. Experience with FCV-4-478 indicates that both position and demand will yield an extended warning of potential valve cage movement.

Procedure O-PMM-074.10, Main Feedwater System Flow Control Valve Inspection, will be revised to require verification of the cage installation torque during FCV inspections or overhauls. Incorporation of torque verification within the standard valve inspection/overhaul willprevent torque relaxation and eliminate the potential for flow instability to move the valve cage.

All of the Unit 4 feedwater flow transmitter port connectors have now been replaced with 0.065-inch thick 3/8-inch tubing. The Unit 3 port connectors will be replaced during the next Unit 3 refueling outage.

Additional Information There has been one earlier event reported related to Feedwater FCV failure: LER 250/94-006-00. This failure was due to intermittent open circuit in the transducer.

The Institute of Nuclear Power Operations (INPO) LER data base has been searched and no other LERs were found which identify the cause of a reactor trip as the disengagement of the FCV cage from the valve body web.

EIIS Codes are shown in the format [EIIS SYSTEM:IEEE component function identifier, second component function identifier (ifappropriate)]

NRC FORM 366A (6-1996)