ML17353A634
| ML17353A634 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 03/31/1996 |
| From: | NUCLEAR FUEL SERVICES, INC. |
| To: | |
| Shared Package | |
| ML17353A633 | List: |
| 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 Revision 0
Page 1 of 14 L-96-082 ATTACHMENT 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 PDR ADQCK 05000250 I
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JPN-PTN-SEFJ-96-015 Revision 0
Page 2 of 14 L-96-082 ATTACHMENT 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 GROUP INTERPACE TYPE INPUT REVIEW NIA PREPARED VERIPIED APPROVED PPL APPROVED>>
MECH ICC CIVIL NUC" CSI NUC PUEL x
~ Por Contractor Evals As Dotormlnod By Projocts and PLAs FPL PROJECTS APPROVAL:
Ori inal si OTHER INTERFACES
- ~ Rovlow Intorfaco As A Mln On All IOCPR50.59 Evals ed b Mana er Nuclear Fuel DATE: 3-12-96
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~ JPN-PTN-SEFJ-96-015 gevision 0
Page 3 of 14 L-96-082 ATTACHMENT PAGE 8
OF 23 Control Rod Operability Evaluation as a Result of Incomplete Rod Insertion at Other Westinghouse Plants TABLE OF CONTENTS Section
1.0 Background
2.0 Description and Purpose 3.0 Licensing Requirements 4.0 Evaluation 5.0 Safety'Analysis 6.0 Conclusions Pa e Number 12 7.0 References 14
JPN-PTN-SEFJ-96-015 Revision 0
Page 4 of 14 L-96-082 ATTACHMENT 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 Revision 0
Page 5 of 14 L-96-082 ATTACHMENT 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 drop time from the fully withdrawn position shall be less than or equal to 2.4 seconds from beginning of decay of stationary gripper coil voltage to dashpot entry.
JPN-PTN-SEFJ-96-015 Revision 0
Page 6 of 14 4.0 Evaluation L-96-082 ATTACHMENT PAGE 11 OF 23 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 Revision 0
Page 7 of 14 L-96-082 ATTACHMENT 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 REVISION 0 PAGE 8 OF 14 TABLE4.1 L-96482 ATTACHMENT Page 13 of 23 Turkey Point Unit 3 Cycle 15 Core Location Rod Bank Current Bumup Typo of (as of 3/10/96)
Fuel MWD/MTU Bumup at Projected EOC Last Scram 8urnup (2/9/96)
MWD/MTU MWD/MTU Observations E45 L45 L-11 E-11 F48 H46 K48 H-10 C47 G-03 J-03 N47 N-09 J-13 G-13 C49 E47 G45 J-05 L47 L-09 J-11 G-11 E49 B46 F42 K-02 P46 P-10 K-14 F-14 B-10 D46 F-04 K44 M46 M-10 K-12 F-12 D-10 D48 H44 M48 H-12 H-08 SBB SBB SBB SBB SBB SBB SBB SBB SBA SBA SBA SBA SBA SBA SBA SBA CBA CBA CBA CBA CBA CBA CBA CBA CBB CBB CBB CBB CBB CBB CBB CBB CBC CBC CBC CBC CBC CBC CBC CBC CBD CBD CBD CBD CBD OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFNDRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFNDRFA 23,330 23,330 23,330 23,330 35,300 35,300 35,300 35,300 20,800 20,800 20,800 20,800 20,800 20,800 20,800 20,800 23,600 23,600 23,600 23,600 23,600 23,600 23,600 23,600 18,300 18,300 18,300 18,300 18,300 18,300 18,300 18,300 30,700 30,700 30,700 30,700 30,700 30,700 30,700 30,700 23,400 23,400 23,400 23,400 38,200 37,500 37,500 37,500 37,500 46,900 46,900 46,900 46,900 34,000 34,000 34,000 34,000 34,000 34,000 34,000 34,000 37,400 37,400 37,400 37,400 37,400 37,400 37,400 37,400 26,800 26,800 26,800 26,800 26,800 26,800 26,800 26,800 43,100 43,100 43,100 43,100 43,100 43,100 43,100 43,100 36,000 36,000 36,000 36,000 49,400 22,500 22,500 22,500 22,500 34,600 34,600 34,600 34,600 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 22,900 22,900 22,900 22,900 22,900 22,900 22,900 22,900 17,800 17,800 17,800 17,800 17,800 17,800 17,800 17,800 30,000 30,000 30,000 30,000 30,000 30,M0 30,000 30,000 22,700 22,700 22,700 22,700 37,600 Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Fulllnsertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Fuilinsertion FullInsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion
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.JPN-PTIP-SEF J-96-01 5 REVISION 0 PAGE 9OF14 TABLE4.1 Turkey Point Unit 4 Cycle 15 L-96482 ATTACHMENT Page 14 of 23 Core Location Rod Bank Current Bumup Typo of (as of 3/10/96)
Fuel MWD/MTU Approximate EOC Bumup MWD/MTU Bumup at TripTest (3/4/96)
MWD/MTU Observations E<5 L%5 L-11 E-11 F-08 H46 K48 H-10 C47 G43 J-03 N47 N49 J-13 G-13 C49 II EW7 G45 J-05 LZ7 L%9 J-11 G-11 E-09 B46 F%2 K%2 P-06 P-10 K-14 F-14 B-10 D-06 F44 K-04 M-06 M-10 K-12 F-12 D-10 D%8 H44 M-08 H-12 H-08 SBB SBB SBB SBB SBB SBB SBB SBB SBA SBA SBA SBA SBA SBA SBA SBA CBA CBA CBA CBA CBA CBA CBA CBA CBB CBB CBB CBB CBB CBB CBB CBB CBC CBC CBC CBC CBC CBC CBC CBC CBO CBD CBD CBD CBO OFA/DRFA OFNDRFA OFA/DRFA OFNDRFA OFNDRFA OFNDRFA OFNDRFA OFA/DRFA OFNDRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFNDRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFNDRFA OFA ln Refueling In Refueling In Refueling In Refueling In Retueling In Refueling In Refueling In Refueling In Refueling In Refueling In Refueling In Refueling In Retueling In Refueling In Retueling In Retueling In Refueling In Retueling In Refueling In Refueling In Retueling In Retueling In Refueling In Retueling In Retueling In Retueling In Retueling In Refueling In Refueling In Retueling In Retueling In Refueling In Retueling In Retueling In Retueling In Retueling In Refueling In Retueling In Retueling In Retueling In Refueling In Refueling In Retueling In Retueling In Refueling 43,800 43,800 43,800 43,800 34,300 34,300 34,300 34,300 31,600 31,600 31,600 31,600 31,600 31,600 31,600 31,600 42,000 42,000 42,000 42,000 42,000 42,000 42,000 42,000 26,000 26,000 26,000 26,000 26,000 26,000 26,000 26,000 47,900 47,900 47,900 47,900 47,900 47,900 47,900 47,900 34,000 34,000 34,000 34,000 50,800 43,800 43,800 43,800 43,800 34,300 34,300 34,300 34,300 31,600 31,600 31,600 31,600 31,600 31,600 31,600 31,600 42,000 42,000 42,000 42,000 42,000 42,000 42,000 42,000 26,000 26,000 26,000 26,000 26,000 26,000 26,000 26,000 47,900 47,900 47,900 47,900 47,900 47,900 47,900 47,900 34,000 34,000 34,000 34,000 50,800 Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Full Insertion Fulllnsertlon FullInsertion Full Insertion Fulllnsertion Full Insertion Full Insertion Full Insertion Full Insertion Fullinsertion Fulllnsertion Full Insertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulltnsertion Fulllnsertion Fulllnsertion Fulllnsertion Fulllnsertion
.JPN-PTA-SEF J-96-015 REVISION 0 PAGE 10 OF 14 TABLE4.1 Turkey Point Unit 4 Cycle 16 L-96482 ATTACHMENT Page 15 of 23 Core Location Rod Bank Bumup Type of at BOC Fuel MWD/MTU Projected EOC Bumup at Bumup Last Scram MWD/MTU MWD/MTU Obsenratlons E45 L-05 L-11 E-11 F48 H46 K48 H-10 C47 G43 J-03 N47 N49 J-13 G-13 C-09 E47 G45 J-05 L47 L49 J-11 G-11 E49 B-06 F42 K-02 P46 P-10 K-14 F-14 B-10 D46 F44 K44 M46 M-10 K-12 F-12 D-10 D48 H44 M48 H-12 H48 SBB SBB SBB SBB SBB SBB SBB SBB SBA SBA SBA SBA SBA SBA SBA SBA CBA CBA CBA CBA CBA CBA CBA CBA CBB CBB CBB CBB CBB CBB CBB CBB CBC CBC CBC CBC CBC CBC CBC CBC CBD CBD CBD CBD CBD OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFNDRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA OFA/DRFA OFA/DRFA OFNDRFA OFA/DRFA 30,400 30,400 30,400 30,400 18,100 18,100 18,100 18,100 15,500 15,500 15,500 15,500 15,500 15,500 15,500 15,500 18,100 18,100 18,100 18,100 18,100 18,100 18,100 18,100 17,600 17,600 17,600 17,600 17,600 17,600 17,600 17,600 17,800 17,800 17,800 17,800 17,800 17,800 17,800 17,800 18,100 18,100 18,100 18,100 34,500 46,600 46,600 46,600 46,600 38,000 38,000 38,000 38,000 34,500 34,500 34,500 34,500 34,500 34,500 34,500 34,500 37,400 37,400 37,400 37,400 37,400 37,400 37,400 37,400 29,100 29,100 29,100 29,100 29,100 29,100 29,100 29,100 36,500 36,500 36,500 36,500 36,500 36,500 36,500 36,500 36,600 36,600 36,600 36,600 50,100 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A NIA N/A N/A, N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A NA N/A N/A N/A N/A N/A N/A N/A N/A NA N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A NA N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A OFA =15x15 Optimized Fuol Assembly DRFA = Debris Resistant Fuel Assembly (FPL Design)
JPN-PTN-SEFJ-96-015 Revision 0
Page 11 of 14 L-96-082 ATTACHMENT PAGE 16 OF 23 TABLE 4.2 SHUTDOWN REQUIREMENTS AND MARGINS Control Rod Worth
'.b, Unit 3
C cle 15 EOL Unit 4 C cle 16 EOL All Rods Inserted Less Worst Stuck Rod 6.23 6.12 (1) Less 7'-.
5.79 5.69 Control Rod Re uirements Reactivity Defects (Doppler, Tavg Void, Redistribution)
Rod Insertion Allowance 2.78 0 '0 2.75 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 Revision 0
Page 12 of 14 L-96-082 ATTACHMENT 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 trip reactivity of 4.0% bp is assumed in this analysis with the worst stuck rod assumed.'he 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 trip reactivity of 4.0% bp is assumed in this analysis with the worst stuck rod assumed.
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 Revision 0
Page 13 of 14 L-96-082 ATTACHMENT 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 Revision 0
Page 14 of 14 6.0 Conclusions L-96-082 ATTACHMENT PAGE 19 OF 23 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 ANDLIGHTCO ANY TURKEYPOINT NUCLEAR UNIT3, 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 I5 NF4N HF~
NF 14 EE06 EE41 FF31 EE28 GG46 GG54 EE27 FF49 GG03 EE45 I1t))TWZ L41 GG49 GGI 3 FF.18 GG23 GG38 FF21 GG40 FF30 L4)
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l4t)IWZ lit)ttWZ l4t)IWZ k)4 HF.II FF35 GG59 EE48 GG32 EE54 GG20 EE44 GG17 EE53 GG26 EE46 GG53 FF34 14t)4WZ Itt)OWZ Ittt)WZ 14tS)WZ L IOA EE36 GGS I GG06 FF23 GG30 FF3 8 GG04 FF29 GG I I FF19 GG25 GG45 EE16 IltlltWZ k ll l4FSSWZ k 1) lit))IWZ RHS Ittt)WZ l)t)tlWZ EE25 FFSO GGI4 EESO Ilk)4)WZ EE31 GG52 GG60 FFOI FF12 FFI3 EE49 LD)
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RRPP Reload Cycle 12 SSf 0 Reload Cycle 13 TTIr4r Reload Cycle 14 UUfIr Feed Cycle 15 RIP Control Rod HFP 0 Hafnium Insert PPPPPIWZ Waba Ineert UU32 SS31 UU44 20PISWZ TT37 R63 TT48 R67 UU52 RR36 HF06 SS16 TTIS R74 RR07 HF16 RA34 HF23 UU36 UUI7 UU39 20P43WZ TT43 R80 UU27 SS34 SS21 LMEND:
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ATTACHMENT7 (Page 1 of 1)
REACTOR FUEL LOCATIONDIAGRAM TURKEYPOINT UNITNO.~
CYCLE NO. 1(o L-96-082 ATTACHMENT PAGE 22 OF 23 15
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8 7
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VV20 VV48 TT14 HF13 TT27 HF15 VU3d W62 10PO UU01 3
UV12 VR72 W22 12P309 W25 BP224 TT13 W30 SP235%
VU13 VV02 W23 11P370VRS VV03 UV33 10PO TT20 HF05 HF20 W43 UV47 UV27 UV14 RBS VV17 SP220 TT41 W32 SP23'I W33 BP23 W1 1 W31 W52 W4S A101 TT07 HF02 VU38 A71 W37 10P5 VU19 TT39 Wl 1 1 2P350WZ VV30 VVOO 3
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L-96-082 ATTACHMENT PAGE 23 OF 23 TURKEY POINT FUEL ASSEMBLY DESIGN Description Fuel Assembly Array/Design Fuel Rod Material Spacer Grid Material Guide Thimble Material Guide Thimble Inside Diameter Length of Guide Thimbles 15 x 15 Debris Resistant Fuel Assembly (Optimized Fuel Assembly)
Zircaloy Top and Bottom Grids: Inconel Intermediate Grids: Zircaloy Zircaloy Above Dashpot - 0.499 in.
Below Dashpot - 0.455 in.
Length of the Dashpot - 23.245 in.
152.970 in.
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20 Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 003687003
Subject:
Turkey Point Unit4-Reportable Event: 2000-001-00, on January 24, 2000, Manual React or Trip due to Main Feedwater Flow Control Valve Cage Disengagement Page 1
Sody:
Distri52.txt 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 ofEvent: 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 ofthe 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 an FPL Group company HL gQQQ Q 7 0+0
NRC FORINT 366 (6-tS98)
U.S. NU REGULATORYCOMMISSION
~
LICENSEE EVENT REPORT (LER)
(See reverse for required number of digits/characters for each block)
APPROVED B NO. 31504104 EXPIRES 06/3pf2001 Estimated burden per response to comply with this mandatory informs<<~
coliecdon request: 50 hrs. Reported lessons learned ere incorporated into ih'icensing process snd fed back to indusby. Forward comments records burden estimate to the Records Management Branch (TA F33), U.S. gucie r Regulatory Commission, Washington. DC 205554001. end to the Paperwork Reduction proiect (31~104).
Ofrce of Management end
- Budget, 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 MONTH DAY YEAR YEAR SEQUENTIAL REVISION MONTH DAY NUMBER NUMBER 01 24 2000 2000 001 00 02 23 2000 OPERATING MODE (9) 20.2201(b) 20.2203(a)(2)(v)
THIS REPORT IS SUBMITTED PURSUANT TO THE RE ck one or more) (11) 50.73(a)(2)(i) 50.73(a)(2)(viii)
QUIREMENTS OF 10 CFR ti: (Che POWER LEVEL(10) 95 f";.~fj'glgl'ggttft'i'$Pje'?ji 20.2203(a)(2)(i) 20.2203(a)(2)(ii) 20.2203(a)(2)(iii) 20.2203(a)(2)(iv) 20.2203(a)(3)(ii) 20.2203(a)(4) 50.36(c)(1) 50.36(c)(2) 20.2203(a)(1) 20.2203(a)(3)(i) 50.73(a)(2)(ii) 50.73(a)(2)(iii) 50.73(a)(2)(iv) 50.73(a)(2)(v) 50.73(a)(2)(vii) 50.73(a)(2)(x) 73.71 OTHER Specify In Abstract below or in NRC Form 386A NAME LICENSEE CONTACT FOR THIS LER 12 TELEPH N
NUMB R(lnerudeAree e)
Stavroula Mihalakea, Licensing Engineer (305) 246 - 6454 CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX SJ FCV C635 YES (IIyes, complete EXPECTED SUBMISSION DATE).
X NO EXPECTED SUBMISSION DATE (15)
MONTH DAY YEAR ABSTRACT (Limitto 1400 spaces, i.e., approximately 15 single-spaced typewritten lines) (16)
At approximately 7:30 AMon 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 AMfeedwater flow appeared to increase causing a SG level deviation. The Operators placed FCV-4-478 in manual operation. A preliminary determination ofvalve 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 fullyinserted and all systems except Feedwater functioned as designed.
The immediate cause ofthe reactor trip was a manual action taken by the RCO in response to Main Feedwater flow instabilities. The underlying cause ofthe trip was a failure in FCV-4-478 valve internals. The valve cage had disengaged from the valve body web. The root cause ofthe failure of FCV-4-478 is inadequate change management in the 1980's when the practice ofperiodic replacement ofthe cage was stopped; specifically, FPL failed to require periodic re-torque ofa re-used FCV cage.
FCV-4-478 was repaired.
FPL established inspection controls to monitor for signs ofvalve degradation.
Cage torque willbe verified for all feedwater FCV at the next opportunity.
NRC FORM 388 (6-1998)
NRC FOR5ll 366A (6-1998)
LlCENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEARREGULATORYCOMMIggl
~10)(
FACILITYNAME(1)
Turkey Point Unit 4 DOCKET NUMBER (2) 05000251 LER NUMBER (6) yEAR SEQUENTIAL REVISION NUMBER NUMBER 2000 001 00 PAGE (3)
Page 2 of 7 TEXT(Ifmom space is mqljifed, use additionai copies ofNRC 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) [SJ: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 ofa.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 ofearlier 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 flowcontrol stability. Apreliminary field determination ofvalve 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. Allrods [AA:rod]were fullyinserted 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 flowcontrol 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 of554 degrees F, as expected.
FCV-4-478 did not fullyisolate for approximately 100 seconds, allowing approximately 10% ofthe nominal feedwater flowinto 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. AllSG 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 ofthe 3/8 inch port connector [JB:A,con] with a 3/4-inch x 3/8-inch adapter.
The port connector failure likelyoccurred as a result ofthe nearby SG "A"piping deflections during FCV-4-478 flow instabilities. FPL found no further evidence ofdamage to any other major components (piping/supports).
This was determined from the observation ofno insulation damage, no bent or misaligned supports, and no evidence ofexcessive movement.
NRC FORM 366A (6-1998)
NRC FORM 366A (8-1998)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORYCOMMISSION FACILITYNAME (1)
Turkey Point Unit 4 OOCKET NUMBER(2) 05000251 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 2000 001 00 PAGE (3)
Page 3 of 7 TEXT(Ifmore space is tequilo d, use additional copies ofNRC Form 366A) (17)
Background
The Turkey Point Unit 4 Main Feedwater System consists oftwo SG feedwater pumps [SJ:p], two high pressure feedwater heaters [SJ: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 ofeach FCV is a motor operated valve, which is the feedwater isolation valve. Normally the FCV controller willbe in "Auto"with power between 15-100%. During plant operations, the FCV maintains a programmed level ofwater in the steam generator by controlling feedwater flowto 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 validityofthe demand and to isolate the problem to either the control system or the valve. Review ofmaintenance and calibration records, field inspections, measurements of feedwater flowfor all FCVs (for comparison purposes), and an examination ofperformance 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 ofinternal problems), and significant vibration ofthe 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 fullyclose.
NRC FORM 366A (6.1996)
. NRC FORM 366A (6-1998)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEAR REGULATORYCOMMIS'()
FACILITYNAME (1)
Turkey Point Unit 4 DOCKET NUMBER (2) 05000251 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 2000 001 00 PAGe (3)
Page 4 of TEXT(lfmore spaceis required, use additional copies ofNRC Form 366A) (17)
Failure Analysis The problem originally identified for FCV-4-478 was one ofhigh demand when compared with similar valves for the "B"and "C" SGs. Further examinations ofthe control functions and the actual valve position also validated the demand signal. A number ofpotential 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 ofthreads.
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 ofthreads on the valve body web were destroyed.
The lower set ofthreads were damaged.
FPL believes that the cage could have come loose from the web only by relaxation ofthe 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 ofwear.
FPL did not recognize that periodic re-torquing ofthe valve cage was necessary to correct torque relaxation. The last known torque ofFCV-4-478 took place in 1986.
The root cause ofthe failure ofFCV-4-478 is inadequate change management in the 1980's when the practice ofperiodic replacement ofthe cage was stopped.
The phenomenon ofrelaxation of a threaded fastener over time followingapplication ofan installation torque is not uncommon. In the case offlow control valve cages, the most probable cause for this relaxation is time in service and flow induced loading. For FCV-4-478, the condition ofthe 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 ofthe cage, permitting greater influence from flow instability and perhaps accelerating the cage disengagement.
An examination ofthe 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 ofthe torque occurred in June 1986. It is likelythat thirteen years of service, without re-torque ofthe cage and under constant hydraulic loading, is sufficient time for torque relaxation and cage disengagement.
NRG FORM 366A (6.1998)
NRC FORM 366A (6-1996)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEARREGULATORYCOMMISSI()II FACILITYNAME (1)
Turkey Point Unit 4 DOCKET NUMBER (2) 05000251 LER NUMBER (6)
SEQUENTIAl REVISION NUMBER NUMBER 2000 001 00 PAGE (3)
Page 5 of 7 TEXT(Ifmore space is required, use additional copies o1 NRC Form 366A) (17)
Other evidence ofrelaxation ofinstallation torque is available within the work history at Turkey Point.
Awork 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 likelybecame 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 ofthe cage was eliminated in the 1980s without changing the inspection requirements, since the potential for torque relaxation was not recognized.
Cause ofthe Event The immediate cause ofthe reactor trip was a manual action taken by the RCO in response to Main Feedwater flow instabilities. The underlying cause ofthe trip was a failure in FCV-4-478 valve internals. The valve cage had disengaged from the valve body web. The root cause ofthe disengagement ofthe cage in FCV-4-478 was the failure to recognize that reuse ofthe 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 ofthe 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 ofthat 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 ofthe valve cage does not impact the function ofthe FCV until the loose cage becomes a restriction on flow. Such a condition can be identified by the external symptoms ofhigh valve demand and valve position. The other two Unit 4 SG FCVs were monitored as part ofthe investigation ofFCV-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 willensure no operability concerns develop. Interim monitoring willensure proper valve function until the next refueling outage when valve cage torque can be verified.
Permanent monitoring willcontinue to track valve performance to detect any deteriorating trends in FCV performance.
The manual reactor trip resulted in an automatic turbine trip. The trends ofnuclear 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 (0-1098)
LICENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEARREGULATORYCOMMISSION FACILITYNAME (1)
Turkey Point Unit 4 DOCKET NUMBER (2) 05000251 LER NUMBER (6)
SEQUENTIAL REVISION NUMBER NUMBER 2000 001 00 PAGE (3)
Page 6 of 7
TEXT(Ifmore space is tequl)ed, use additional copies ofNRC Form 366A) (17)
Following the reactor trip, a feedwater isolation signal was generated on reactor trip with RCS average temperature of554 degrees F. FCV-4-478 did not fullyisolate, allowing approximately 10% ofthe nominal feedwater flow into the "A"SG for approximately 100 seconds (normally the valve closes in 20 seconds).
In case offailure ofthe FCV, termination offeedwater 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 ofthe 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 ofthe secondary system thus resulting in a primary system cooldown. The cooldown ofthe primary system willcause a power increase due to negative reactivity feedback.
The current analysis assumes one feedwater FCV malfunctions resulting in a step increase to 200% ofthe nominal feedwater flow to one SG. The assumptions and results ofthe analysis in the UFSAR bound the conditions ofthe actual event, i.e., the total amount of feedwater added to the SG in the safety analysis is significantly greater than the amount offeedwater added as a result ofthe 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 flow,'ith the intact SG receiving the nominal feedwater flow. The results ofthe analysis (factoring in the malfunction ofthe FCV occurring in either the faulted or intact SGs) conclude that fuel cladding damage is not likelyto occur since the 95/95 Departure from Nucleate Boiling (DNB) ratio limitis satisfied. Therefore, because the assumptions and results ofthe analyses in the UFSAR bound the conditions ofthe actual event, this event did not compromise the health and safety ofplant 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 ofthe temporary repair as a permanent modification ofFCV-4-478.
NRC FORM 386A (6.1998)
0
NRC FORM 366A (6-1996)
LlCENSEE EVENT REPORT (LER)
TEXT CONTINUATION U.S. NUCLEARREGULATORYCOMMISSION FACILITYNAME (1)
Turkey Point Unit 4 DOCKET NUMBER (2) 05000251 LER NUMBER (6)
YEAR SEQUENTIAL REVISION NUMBER NUMBER 2000 001 00 PAGE (3)
Page 7 of 7 TEXT(Ifmore spaceis required, use additional copies ofNRC Form 366A) (17) 3.
FPL reviewed maintenance records for all six valves, which represents all ofthe valves ofthis design at Turkey Point Units 3 and 4. Records indicate that four of the valves had their valve cage torque inspected.
No records ofany inspection were found for the Unit 3 FCV-3-498.
Interim monitoring ofall (total ofsix) Turkey Point Units 3 and 4 Main Feedwater FCVs demand willbe used to identify unusual trends in demand, indicative ofpotential cage disengagement.
FPL willmonitor and record the demand position for each Feedwater FCV once per shift until each ur)it's next refueling outage when cage torque willbe verified.
Permanent monitoring ofthe 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 willyield an extended warning of potential valve cage movement.
Procedure O-PMM-074.10, Main Feedwater System Flow Control Valve Inspection, willbe revised to require verification ofthe cage installation torque during FCV inspections or overhauls. Incorporation oftorque verification within the standard valve inspection/overhaul willprevent torque relaxation and eliminate the potential for flow instability to move the valve cage.
Allofthe 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 willbe 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 ofNuclear 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 ofthe 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)