ML20090J859
| ML20090J859 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 09/24/1987 |
| From: | Lainas G Office of Nuclear Reactor Regulation |
| To: | Gibson A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| Shared Package | |
| ML082380335 | List:
|
| References | |
| FOIA-91-106 NUDOCS 8709300194 | |
| Download: ML20090J859 (3) | |
Text
7
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ENCLOSURE l
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UNITED STATES NUCLEAR REGULATORY COMMISSION a
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- l wAssiwatow o.c.20sss September 24, 1987
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Docket No. 50-338 HEMORANDlN FOR:
Albert Gibson, Director Division of Reactor Safety, RI!
FROM:
Gus C. Lainas, Assistant Director for Region II Rcactors Division of Reactor Projacts I/11 Office of Nuclear Reactor Regulation
SUBJECT:
TIA - MORTH ANNA UNIT 1 (NA-1) STEAM GENERATOR TijBE FAILURE EVENT The purpose of this memorandum is to update our interface agreement dated 1987, relative to the recent North Anna Unit 1, steam generator tube July 28,(SGTR) event. A copy of the July 28, 1987 interface agreement is pro-rupture vided in Enclosure 1.
The first 3 items specified in this agreement have been completed. Items 4 and 5 still remain to be done.
Virginia Electric and Power Company (VEPCO) and Westinghouse (W) have been ivaluating this event and have just recently finalized the tube break mechanism
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and modifications required prior to 'estart.
On September 10, 1987, VEPCO and W briefed the HRR and Region II (PII) staff i
on the NA-1 steam generator inspection, the SGTR failure mechanism and the modificaticns to be made prior to restart.
Final reports from VEPCO and W were submitted to NRR on September 15, 1987. VEPC0 and W met with the NRR and the RII staff on September 21, 1987 to discuss questions from the staff re-garding these firal reports. On September 23, 1987 VEPCO will suhnit a basis for restart with plar.t operations limited to 50% of full power pending staff authorization of full power operation. The NRR Project Manager, Leon Engle, has already discussed restart limited to 50% of full pcwer with RII represen-tatfves. Also, on September 75,1987, VEPC0 will submit as part of its final SGTR report, a safety evaluation revising dose rt.tes for the UFSAR SGTR acci-dent analyses based on the installation of SG downcomer resistance plates.
Finaily, full power operaticn is dependent on the NRR SER regarding the NA-1 SGTR event, and the evaluation and adequacy cf the SG repairs.
Therefore, based on tha above, a revised interface agreement is necessary as is an updated schedule for meeting major milestone requirements. A revised schedule is providec in inclosure 2 to this memorandum.. The listed dates are based on the best available infonnation at this time.
The following actions specify both RII and NRR responsibilities, as well as the ioint actions required prior to restart (50% power) and full power operations 1100% power).p-m v
f Albert Gibson 1.
RII and NRR inet with licensee on September 21, 1987.
The NRR draft SER for restart (50% power) is scheduled to be prepared by 2.
September 30, 1987.
(The NRR NA project manager will have lead responsi-bility for preparing the draft SER.)
The NRR draft SER for restart (50% power) is scheduled to be sent to NRR 3.
EMTR and PSB and RII for concorrance on September 30, 1987.
4.
NRR and RII concurrence on draft SER f50% power) is scheduled for October 2, 1987.
5.
NRR SER for restart (50% power) is scheduled to be issued on October 5, a
- 1987, RII is requested to verify the following items prior to restart (Mode 2).
T 6.
The adequacy of the licensee's operatini procedures for SG leakage rate i
surveillance.
That SG tube R9 CSI has been stabilized in conformance with vendor (W) recommendations.
That flow restrictor plates have been installed in conformance with vendor
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reconinendations.
Thit applicable procedures have been followed for loose parts accountability.
3 7.
RII/NRR agreement on approval for test et (50% power) is scheduled to be completed by October 5, 1987.
j I
8.
RII is scheduled to issue not later than October 6, 1987 a revised CAL to licensee which would limit power operations to 50% power.
9.
MI will verifj the operability of the newly installed N-16 monitor prior to power ascension greate than 30%.
- 10. NRR ENTB, PSB and PRBP SER input for full power operations is scheduled to be submitted to the PM by October 9, 1987.
- 14. RII/NRR approval for full power operations is scheduled to be complete on October 19, 1987.
I
Albert Gibson It is noted that additional actions and responsibilities way be identified as the staff's review of thete matters progresses.
The contact for the above actions will be L. Engle, eho can be reached on FTS 49-29795, fyaf -
us C. Lainas Assistant Director for Region 11 Reactors Division of Reactor Projects I/II Office of Nuclear Reactor Regulation
Enclosures:
As stated ec:
T. Hurley J. N. Grace L. Reyes J. Sniezek F. Miraglia R. Starostecki J. Richardson A. Thadani L. Cunningham F.'Cantrell C. Y. Ch?ng R. Craig
u Octbbar 8, 1987
.j Docket Ns. 50-338 MEMORANDUM TO:
Luis A. Reyes, Director Division of Projects, Region II FROM:
Gus C. Lainas, Assistant Director for Pegion II Reactors Division of Reactor Projects-l/II SU4 JECT:
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO RESTART AND OPERATION OF NORTH ANNA. UNIT NO. 1 (NA-1), AT 50 PERCENT POWER The subiect NA-1 Safety Evaluation (SE) dated October 5,1987 is enclosed in accordance withthe revised TIA dated September 24, 1987 regarding the NA-1 steam generator tube rupture event, t
As stated in the NA-1 SE, the NO.R staff finds that interin operation et reduced power (less than or ecual to 50 percent power) is acceptable _.
Region 11 roncurrence on the subject SE was received on October 2,1987 in a telecon between F. Cantrell, Region II, and the NRR Prn.iect Manager, L. Engle.
hRR will review, in conjunction with R-II, the results of operation at 50 percent Prior to power as well as the licensae's evaluation of SG tube perfonnance.
authorization for operation at greater than 50 percent power, the staff will
_ evaluate the operating results and other information and issue a final safety evaluation report.
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Original signed by Gus C. Lainas, Assistant Director for Region II Reactors Division of Reactor Projects-I/II
Enclosure:
As stated cc w/ enclosure:
T. Murley J. Sniezek R. Starostecki F. Miraglia J. Richardson A. Thadani DISTRIBUTION Docketi File PD22'Rdg'.
G. Lainas H. Berkow B740140155-G71008~
Engle E
L'. Miller OEjg2 s
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- Please see previous concurrente 1
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PM:PDII-2*
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I cd DMiller LEngle HBerkow Glainas 10/06/87 10/06/87 10/05/87 10/06/87
Docket No, 50-338 MEMnRANDUM T0:
Luis A. Reyes, Director Division of Projects, Region II FROM:
Gus C. Lainas, Assistant Director for Region II Reactors Division of Reactor Projects-!/f f
SUBJECT:
SAFETY EVALVATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED 70 RE; TART AND OPERATION OF NORTH ANNA, UNIT d. 1 (NA-1), AT 50 PERCENT POWER The subject NA-1 Safety Evaluation (SE) dated October 5,1987 is enclosed in accordance withthe revised TIA dated September ?4,1987 regarding the NA-1 steam generator tube rupture event.
As stated in the NA-1 SE, the NRR staff finds that interim operation at reduced power (less than or equal to 50 percent power) is acceptable. Region il concurrence on the sub.iect SE was received on October 9, 1987 in a telecon between F. Cantrell, Region 11, and the NRR Proiect Manager, L. Engle.
s Gus C. Lainas, Assistant Director for Region II Reactors Division of Reactor Projects-I/II EnclostiYe:
As stated cc w/ enclosure:
T. Murley J. Sniezek R. Starostecki F. Miraglia J, Richardson A. Thadani DISTRIBUTION Docket File PD22 Rdg.
G. Lainas H. Berkow L. Engle D. Miller fay j/
L I-2 PM D:
/ ?
- :DP?A DMiller LEn le He j
ilainas
- G/f/87
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10/(/87 10/fo/87 10/6/87 t
A SAFETY EVALUATION BY--THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO RESTART AND OPERATION AT 50% POWEA FACILITY-OPERATING LICENSE E NPF-4 VIPINIATLECTRIC AND POWER COMPANY J
T D DOMINICN ELECTRIC COOPERATIVE-NORTH ANNA POWER STATIONn UNIT NO.1 DOCKET NO. 50-33_8 4
INTRODUCTION By letter dated September 22, 1987, the Virginia Electr'c and Power Ccmpany l
(the licensee) requesteo that the Notth Ann Power Station, Unit No. 1 (NA-1) be permitted to start up and operate at 50 percent of full power.
Following the July 15,1987 NA-1 Steam Generator Tube Rupture (SGTR) event, the licensee 4
agreed to obtain concurrence-from the NRC prjor to NA-1 restart (Mode ?).
T5fs agreement was specified in the NRC Confirmatory Action Letter (CAL) i> sued July 22, 1987. The licensee has completed the evaluation of the-SGiR event and has submitted by letters dated September 15 and 25, 1987 the evaluation of the SGTR event, including the SGTR failure mechanism and modifications to be made prior to restart. The NRC review cf these' matters may extend beyond early October, 1987 when NA-1 is-scheduled to be ready for restart.
Therefore, as noted above, the licensee has requested NRC concurrence for restart and opera-
"-tion of NA-1 at 50 percent of full power pending NRC authorization for full power operations.
In ' order to place these matters in-proper perspective, a brief escription of the NA-1 SGTR event and the' licensee's investigation of
,[
this n ant is provided below.
Prior to 0630 hours0.00729 days <br />0.175 hours <br />0.00104 weeks <br />2.39715e-4 months <br /> on July 15, 1987, WA-1 was operating at 100% power.
At 0630 hours0.00729 days <br />0.175 hours <br />0.00104 weeks <br />2.39715e-4 months <br />, the Main Steam Line "C" radiation monitor registered a Hi-Hi alarm and the Control Room Operator (CRO) noted pressurizer (PZR) level and pressure decreasing.
Therefore, the CR0 increased charging flow to the Reactor Coolant System (RCS). The unit was manually tripped at 0635 hours0.00735 days <br />0.176 hours <br />0.00105 weeks <br />2.416175e-4 months <br /> and approximately n
L l
20 seconds later a Lo-Lo pressure safety injection signal-actuated automatic trip. 'At-0639 hours a Notification of Unusual Event was declared and at 0650 f
hours.feedwater flow to SG "C" was isolated.
However, the level of SG "C" was s.
identified to be increasing, indicating an SG tube: rupture or break (SGTR).
At 0654' hours an alert was declared and at 0705 hours0.00816 days <br />0.196 hours <br />0.00117 weeks <br />2.682525e-4 months <br /> SafetyiInjection (SI) was i
terminated.
At.0710 hours0.00822 days <br />0.197 hours <br />0.00117 weeks <br />2.70155e-4 months <br /> emergency procedures were initiated for post-SGTR l.
cooldown using backfill.
The Technical _ Support Center was activated at 0757 hours0.00876 days <br />0.21 hours <br />0.00125 weeks <br />2.880385e-4 months <br /> ano the local emergency operations facility activated at 0915 hours0.0106 days <br />0.254 hours <br />0.00151 weeks <br />3.481575e-4 months <br />.
The unit entered Mode 4 (Hot-Shutdown) at 1108 hours0.0128 days <br />0.308 hours <br />0.00183 weeks <br />4.21594e-4 months <br /> and at 1218 hours0.0141 days <br />0.338 hours <br />0.00201 weeks <br />4.63449e-4 months <br /> the RHR F-system was placed-in service.
The unit entered Mode 5 (Cold Shutdown) at 1330 e
hours and the event was ttrainated'at 1335 hours0.0155 days <br />0.371 hours <br />0.00221 weeks <br />5.079675e-4 months <br />.
i No automatic actuation of primary or secondary safe relief valves occurred.
l Total radioactivity release was less than 1% of Teci.nical Specification (TS) j limits. The tuba leakage rate (as determined later) was in the range of 560-637 gallons per minute (GPM).
Offsite environmental monitoring teams detected no increase in radioactivity above normal background levels.
The SGTR event was l
l I
5 determined to be bounded by the Updated Finsi Safety Evaluation Report (uFSA.).
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The maximum leak rate (560-637 gpm) was less than the UFSAR value of 710 qpm.
Core safety limits were nct challenged and shutdown and thermal margins were maintained.
Once access to the NA-1 SGs A, B, and C was gained, the licensee's evaluation of (1) Determining the root cause of the failure; the SGTR event was oriented to:
(2) Ascertaining the condition of the SGs, particularly with respect to the failure mechanism; and (3) Performing the necessary corrective sctions to preclude the future occurrence of a tube rupture event, 21,1987, VtPC0 identified a ruptured tube in SG-C.
The tube location On July was Row 9, Column CSI (M C51) on the cold leg side at the seventh support level.
A fiber optic examination identified the failed tube tu be the classical double-ended guillotine break.
On August 12, 1987, VEPC0 successfully completed the removal of tube R9 C51 on the cold leg side up to and including the break at the seventh support level.
The tube was immediately sent to Westinghouse for an extensive nondest)uctive/ destructive examination to detarmine the frac-ture morphology and the failure propagation mechanism.
The results of these examinations and the determination of the tube failure mechanism are provided in the licensee's final report dated September 15, 1987, and are discussed below, in order to provide justification for future restart of NA-1, VEPC0 has con ~
ducted an extensive inspection of all three SGs.
The inspection has been the most extensive eddy-current testing program undertaken at a U.S. domestic f acility with emphasis on detecting circumferential defects.
- Eddy current testing (ECT) is the principal method used for performing tube inspections. This incpection method involves the insertion of a test coil inside-the tube that traverses the tube length.
The test coil is excited by an alternating current, which creates a magnetic field that induces eddy currents in the tube wall.
Disturbances of the eddy currents caused by flaws in the tube wall produces corresponding changes in the electrical impedance as seen a,t the test coil terminals.
Inst w erts are used to translate these changes in test coil impedance into outpt. voltages which c6n be monitored by the test The depth of the flaw can be deteruined by the observed phase angle operator.
The test equipment is calibrated using tube specimens containing response.
artificially induced flaws of known depth.
The ECT testing program has included the inspection of every tube support junction and straight tube sections in all three SGs with an 8x1 pancake This prcbe (8x1) nas the sensitivity to detect all inner-array proba.
diameter defects, either axial or circumferential, and with defects 20% or deeper and with a length of 3/16 of an inch or longer.
Also, the 8x1 proba is able to detect outer-diameter cracks and intergranular attack on either the inner-or outer-diameter.
In addition, all indications detected by the 8x1 probe have been tested with the Rotating Pancake (RPC) proce.
Finally, pro-filometry has been conducted on selected intersections.
A Westinghouse Inte'ligent Eddy Current Data Analysis System (IEDA) has been used as an aid in flagging suspect bobin coil indications, which are then dispositioned by data analysts. The data from each tube has been independently reviewed by two different analysts.
One analyst has used the Westingnouse IEDA system and the other analyst has used the Zetec Digital Data Analysis System.
2
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All data analy's'ts are certified at least Level II in accordance with American-Society of Nondestructive Testing (ASNT) requirements.
The analysts have been given additional training by Westinghouse and required to pass a test that covers the specific data analysis being used for the present NA-1 eddy current
- tests, Finally, it is noted that an NRC Augmented Inspection Team (Ali) was dispatched to the NA facility.
The AIT was charged with determining whether the licensee's actions in response to the July 15, 1987 SGTR were adequate to protect the health and safety of the public and that appropriate action was being initiated to determine the cause of the event.
In addition, the procedures followed by the licensee relative to the SGTR were evaluated to assess the adequacy of in place procedures to cope with serious events of this type.
The NRC AIT Report was issued August 28, 1987.
The Report, in part, concluded that, "The overall results achieved were outstanding in that the operator tripped the plant, isolated the leak and brought the plant to cold shutdown in seven hours without using the S/G power-operated relief valves.
This centributed to a negligible release to the environment."
Our discussion and ev'aluation of these matters with respect to restart of NA-1 for operations not to exceed 50% of full power are provided below.
DISCUSSION Steam Generator Inspection As noted above, the licensee conducted an extensive SG ECT inspection of the NA-1 SGs A, B and C.
Identified indica.tions were either present in the April 1987 vefueling outage with no discernable change indicated or in previously uninspected portions of each SG.
Additionally, a review of the data from the last outage using the present analysis rules revealed several tubes that should have been plugged at the previous outage.
This apparent, though not actual, change in the SG condition is due to the change in the analysis rules and in-creased awareness by the analysts of North Anna specific ECT signals.
A review and comparison of the SG C hot leg data demonstrates that there ic essentially no change in tube condition from the April 1987 refueling outage to July 1987 (when the event occurred).
Of significant importance was the fact that there were no indications of circumferential nature found at any tube support plate locations, including the seventh tube support plate.
The number of tubes inspected is shown below.
Each steam generator contains 3388 tubes.
tiowever, a numbe of tubes have been plugged from previous SG inspections. The number of noa plugged tubes are:
SG A - 3179; SG 8 - 3210; and SG C - 3117.
The number of tubes to be removed from service based on the SGT inspection by indication type are indicated in the following table.
3
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1 STEAM GENERATOR TUBES T0 bi PLUGGED AS RESULT OF SGTR EVENT _
(By Indication Type)
Tota 18 Tubes tubes Cleart Distorted 2 Sheet 8x1 Possible4 to be Sj_G Indicatiar.s Indications Indications Ir.dications Other5 Pluggsf A
0 6
6 11 2
25 B
0 3
5 12 1
21 C
2 2
20 11 4
39 1 Clear Indications (defective) - bobbin indications of greater than 40 percent "thru-wall" depth.
2Distorteb Indicctions - bobbin indications of undetermined "thru-wall" depth at tube support plates.
3Tubesheet indications - bobbin indicatioiis of undetermined "thru-wall" depth at tubesheet.
46x1 Possible Indications - indications identified by 8x1 probe.
_ STubes with broken probes or which would not pass 8x1 probe - includes failed tube.'
6 Plugging summary is as of 9/14/87 based on ECT results - does not include tubes to be plugged as a preventative measure based on fatigue considerations or other concerns.
Tube Failure Mechanism Upon arrival at Westinghouse, tube R9 CSI (the tube with the circumferential break) was immediately subject to a series of non-destructive / destructive tests to determine the tube failure mechanism. Visual examinations and macroscopic examinations of the tube fracture surface were conducted to determine crack origins and crack propagation paths.
Scanning Electron Microscope (SEM) and Transmission Electron Microscope (TEM) fractographic examinations were also performed to confirm tube crack origins and crack propagation paths.
Mechanical properties of the tube were determined and found to agree closely with the 1971 tube certification data applicable to NA-1.
Microstructure was typical of mill-annealed Alloy 600 for NA-1.
Grain size was small, ASTM 9.5.
No Based on the above, the cause of the failure was determined to be fatigue.
evidence of any si~iificant intergranular corrosion was observed on or immedi-High cycle fatigue striations were ately adjacent to the fracture surfaces.
present and were measured to obtain the stress intensity which led to initiation of the 'atigue crack and crack propagation.
The mode of crack propagation 4
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concluded toat leakage occurred between the time of total through-wall develop-ment of the crack front and the final circumferential break.
The orientation and spacing of the striations supoort the conclusion that
~
normal design operational loadings were not sufficient to lead to the fatigue failure. Therefore, some other loading mechanism was acting on the tube to Measurements of the striation spacing provided necessary produce che failure, data to determine the range of loadings that led to eventual fatigue of the tube.
Adverse flow mechanisms were evalu ced, such as turbulence, vortex shedding, and fluid elastic excitation.
Review of the data supports the con-clusion that fluid elastic excitation was the most procable mechanism that could provide sufficient loadings or alterneting stresses to induce fatigue, An additional method was utilized to determine these loadings and verify the This method striation spacing measurements and resultant loading conditions, used tube dent data (obtained through profilometry and physical measurements) and finite element analysis tu establish mean stress data through the dent.
This mean stress data, the dented configuration and fatigue curve were tnen used to determine the alternating stress intensity required to initiate a fatigue crack.
This calculated range of stress intensity supported the similar
' conclusion determined from striation spacing measurements that tube failure was induced by fatigue.
The sta-A fluid elastic stability ratio was defined for failed tube R9 C51.
bility ratio represents a measure of the potential for tube vibration due to instability during service.
Values greater than unity (1.0) indicate fluid elastic instability.
The fluid elastic stability ratio is defined as the effect.ive velocity divided by the critical velocity.
The calculated flow ratio was determined for current NA-1 flow parameters.
Calculations determined that the tube would be more susceptible to fluid elastic instability due to lower damping' caused by donting. Simulated shaker tests supported the conclusion that in this regipu of low damping, tube R9 CSI would be fluid elastica 11y unstable.
the results of the present SG Inspection indicated no eddy As discussed abov.
current indicatior.: of a circumferential nature at any seventh support plate The location. This is consistent with the fatigue mechanism described above.
majority of the fatigue process lies in the cyclic loading (via alternating stress) to initiate a crack (or cracks) in the tube.
Once the fatigue crack initiates, the time required to propagate the crack is comparatively small.
Antivibration Bars (AVBs) limit the high vibration amplitudes needed to achieve the alternating stress necessary for fatipe crack initiation. The depths of AVB penetration into the SG tube bundle can be estimatea'from eddy current indications that can then be translated to a SG inspection map which provides an indication of non-uniform AVB insertion depths.
A large number of AVB indications were identified during the current SG inspec-This is not unusual in a Series 51 Westinghou>e SG.
However, a few t t :m.
indications were identified as far down as Row 8.
Therefore, extensive eddy current testing was performed to identify AVB indications. The inspection revealed that the majority of the Row 9,10 and 11 tubes were supported by AVBs.
However, failed tube R9 CSI was not supported by an AVB.
l 5
l l
l Correlation with the known deflecticns required to provide sufficient stress to initiate fatigue show that the AVBs limit the tube motion to below the required deflection limit. This data provided further support to the con-clusion that the loading mechanism for R9 C51 was fluid elastic excitation.
In sumary, the licensee concludes that the tube failure was due to high cycle The fatigue mechanism was determined to be a combination of stresses fatigue.
imposed by tube denting at the seventh support plate and vibration due to fluid elastic instabil;ty.
Corrective Actions The licensee has implemented a series of corrective actions and modifications to preclude similar tube failures at NA-1.
These include the installation of a downcomer flow resistance plate in order to reduce the loadings experienced by susceptible tubes.
Preventive SG tube plugging is being implemented to further reduce the probability of tube rupture.
In addition, an enhanced moni-toring program is being implemented to provide sufficient notification of tube These matters are leakage in order to shut down NA-1 prior to a tube rupture.
discussed below.
(1) Downcomer Flow Resistance Plates The NA-1 SGs A, B and C are being modified to include a downcomer flow resist-The DFRP will reduce the steam generator recirculation flow aace plate (DFRP).
and is expected to result in the imprvvement in tube " stability ratio" needed to preclude further tube failures of active tubes by the fluid elestic insta-As noted above, " stability ratio" is a relative measure
- bility mechanism.
Evalua-of the potential for tube vibration due to fluid elastic instability.
tions by the licensee have concluded that a 10% improvement in stability ratin should provide the necessary reduction in fatigue usage (reduced amplitude sf vibration) to preclude further tube failures by this mechanism over the remain-ing life of the steam generators.
The installation of the DFRPs will be com..
pleted prior to NA-1 restart.
For operations at greater than 59 percent power, the Final Safety Analysis Report (FSAR) will be revised to include the DFRP (reduced mass flow) in the A reanalysis of the SGTR event with the OFRP has re-SGTR accident analysis.
sulted in a calculated offsite dose which is greater than reported in the The increase in dose consequences for the SGTR event occurs only for UFSAR.
rated thermal power levels above approxitnately 59%, and the consequences are still well within established acceptance criteria as defi.ned in the UFSAR and the bases for NA-1 TS 3/4.4.8.
(2) Preventive Plugging Preventive plugging will take place on the potentially susceptible tubes in The essential criterion for identifying specific tubes for Row 8 through 11.
All preventive plugging is that they not be supported by at least one AVB.
such tubes will be plugged.
On the cold leg side, each tube meeting this The sentinel plug will plugging criteria will be plugged with a sentinel plug.
permit internal pressurization of the tube and lov level leakage in the event a This will serve as an early through-wall crack develops in the plugged tube.
warning detection method Mr occurrence of a similar circumferential break of 6
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october 16,11987 I
9 3
Docke.t No. 50-338 MEMORANDUM FOR:
Herbert Serkow, Director Protect Directorate - II-2 Div sion of Reactor Projects I/II l
t Chief FROM:
John W. CraiC, Branch Plant Systems Division of Engineering and Systehis Technology UNIT 1 - MODIFICATIONS TO LEAKAGE DETECTION NORTH ANMA,FOLLOWING THE JULY 15, 1987 STEAM GENERATOR
SUBJECT:
CAPABILITY TUBE RUPTURE EVENT (TAC NO. 55791)
Plant Name:
North Anna Power Station, Unit Nc. 1 Licensee:
Virginia Electric and Power Company Docket No.:
50 338 Roview Status:
Complete The Plant Systems-Branch (PSB) has reviewed the Virginia Electric and Power Company's submittals dated September 15 anr1 25, 1987 regarding the steam Unit 1.
generator tube rupture (SGTR) event of July 17, 1987 at North Anna,illance PSB review was limited to the modifications for the augmented surve This program for monitoring steam generator primary-to-secondary leakage.
program is based on-the use of several existing radiation monitors and sampling systems, and the installation of a new N e gamma detection system i
The program is designed to detect to quantify ' primary-to-secondary leakage.
leakage during the early stages of fatigue fcilure so that an orderly shutdown can be~ accomplished prior to an actual SGTR.
to-secondary leakage Based T,n tsar review, we find the proposed primaryken by thg jorityof surveillance program to be beyond the measces ta rrent licensing utilities to detect a possible SGTR event and in excess of age are identified The existing requirements on reactor coolant criteria.
in current Technical Specification Section ? 4.6.2 which s e5fies an al primary-to-allowable limit of one gpm unidentified leakage, one d from the reactor secondary leakage through all steam generators not coolant systems, 500 gallons aer day of leakage tM gh any one steam generator not isolated from tie reactor coolant Astem, and 10 pgm identified leakage from the: reactor coolant system.
With dny of the above leakage conditions present,ithin the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.the plant is to be in The licensee plans to-and cold shutdown w monitors in addition to the existing leakage detection.
-install new H s capability for ensuring that the above technical specification limits are not i
These monitors will alarm in the control room and will provide a-exceeded.
The alarms will conunvous; control room indication in gallons per day (gpd).
have three settings of 10, 60, and 100 gpd above the initial reactor coolant monitor will be installed on the raain steam header activity level. 0ne H s 19 monitor will be i
' initially (prior to restart)_ and subsequently one N installed on each steam generator thus providing an immediate indication of We find the licensees which steam generator has an excessively leaking tube.
proposed design to be acceptable.
9710iiFO"341 ah1016
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ts as Our Safety Evaluation Report input on this subject is provided in Enclosure 1 3
and our SALP input is provided in Fnclosure 2.
We consider our efforts on TAC No. 65791 to be complete.
@!e4 ped by John W. Craig, Chief Plant Systems Branch Divisico of Engineering and Systems Technology
Enclosures:
As Stated cc w/ enclosures:
L. Engle CONTACT: A. Gill X28189 DISTR'BUTION Docket File PSB Rdg Plant File JWermiel JKudrick AThadani LShau AGil' P : E PS ST
/ Ei65ST AGill;cf JWermiel fJCraig 3
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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION PLANI SYSTEMS BRANCH HODIFICATION TO LEAKAGE DETECTION CAPABILITY FOLLOWING THE JULY 15, 1987 STEAM GENERATOR TUDE RUPTURE EVENT j
4 NORTH ANNA POWER STATION, UNIT NO.1 DOCKET NO. 50-338
1.0 INTRODUCTION
25, 1987, the licensee submitted their evaluation of the North Anna, Unit 1 steam generator tube rupture event of
[
By letters dated September l'. and 1
including their assessment of SGTR failure mechanism and planned July 15, 1987 modifications to be made to the leakage detection capability in order to to occurrence of detect a significant steam generator tube degradution prior a tube rupture.
2.0 015CU5510M The 1-icensee has developea an augmented surveillance program for detection j
of primary-to-secondary leakage by identifying the early stages of f atigue failure, so that an orderly shutdown can be accomplished before tube failure The program includes recording and trending of selected radiation occurs.
monitor data, sample isotopics, and more frequent calculation of primary coolant leakage in order to datect leak rates between 10 gallons per day (gpd) and 100 gpd in a timely manner.
This capability will provide assurance that even with f atigue failure, there is adequate time for shutting down the unit This licensee volunteered reactor ccolant leakage prior to exceeding 100 gpd.
limit,is more conservative than existing technical specification limits which require reactor shutdown when one of the following is exceeded:
1.
One (1) gpm unidentified leakaga One (1) gpm total leakage through all unisolated steam generators 2.
Five hundred (500) gpd leakage through any one unisolated steam generator
=
3.
4.
Ten (10) gpm identified leakage Currently primary-to-secondary radiation monitors are located on the condenser air ejector discharge, three mein steamlines, and three steam generator In addition to these indications, the licensee is installing blowdown lines.
new N s detectors, one on the main steam header (to be operable prior to 2
restart) and subsequently, one on each main steam line from the steam These detectors will indicate leakage in gallons per day and will generator.
provide continuous readout in the control ro' n.
monM ars will have three alarm settings that will annunciate in the The N e cnntrol room at 10 to 20, 60, and 100 gpd aoove the initial reactor coolant i
The alarm setpoint will be periodically evaluated and activity level.
adjusted based on primary-to-secondary 'eakage calculations in order to respond to a leak rate of approximately 10 gpd above the maximum current The condenser air ejector alarm will te set consistent with the N s i
value.
first alarm.
The N e second alarm will be set at 60 gpd in order to detect the initial crack propagation of a f atigue failure.
The third N c alana will i
t be set at the administratively imposed shutdown limit of 100 gpd.
- - - - - - -. - - - ~. - -. _ _ _ _
2 The licensee will proviue operating procedures for SG leakage rate surveillance prier to unit restart and will verify operability of these N a t
The licensee will monitors prior to power ascer.sion greater than 30 percent.
record and/or evaluate the monitors data for indications of leakage (trend and magnitude) during modo 1 operation.
The steam generator blowdown monitors and the condenser air ejector discharge monitor will be recorded and evaluated in addition to the above monitors, samples from the air every four hours, ejector exhaust will be taken and anal)1ed every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and from the primary reactor coolant system and secondary coolant (steam generator blowdown) every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The result will then be used to calculate the primary ~to-seconJary leakage during mode 1 operation.
Sample activity levels will also be trended.
The licensee will then use the radiation detector and sampling data to calculate primary-to-secondary leakage every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> based un air ejector exhaust isotopic activities and every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> based on secondary coolant isotopic activities.
The primary isotopic activities will be used to relate the air ejector and secondary isotopi: activities to primary-to-secnndary leakage.
In addition, the condenscr air ejector radiation monitor count rate used to estimate primary-to-secondary leakage every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> readings will b9 and the radiation moaitor alarrn setpoint will be adjustec to respond if leakage increases to and stays at 10 gpd above the most recent maximum leakage measurement.
- 3. 0 CONCLUSION Based on the above, the sta'c concludes that the licensees proposed modification for the augmented surveillance program for monitoring steam generator primary-to-secondary leakage exceeds the requirements iuentified in the existing technical specifications and will or de early indication of
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The staff, steam generator tube degradation prior to occurrence of a rupture.
theref ore, finds the licensees program to be acceptable.
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PSB sat.P,1NPUT 1
Plant Name:
North Anna Power Station, Unft No. 1 Licensee:
Virginia Electric and-Power Company Docket No.:
50-333 SER
Subject:
Modifications to Leakage Detection Capability Following the July 15, 1987 Steam Generator Tube Rupture Event
PERFORMANCE (1) Management Ir.volvement in Assuring Quality PARAMETERS:
(2). Approach to Resolution of Technical Issues frnm a Safety Standpoint i
(3) Response to NRC Initiatives
.(4) Staffing (Including Management)
(5) Reporting and Analysis of Reportable Events (6) Training and Qualification Effectiveness (7) Any other SALP Functional. Area PERFORMANCE NARRATIVE DESCRIPTION OF CATEGORY / RATING PARAMETER LICENSEE'S PERFORMANCE (1)
Not applicable P
(2)
The licensee's proposed steam generatur 1
leakage detection capability is beyond
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that required by existing criteria and will insure early detection of steam
~-
generator tube fatigue prior to occurrence of a rupture.
(3)
The licensee was very prompt and responsive 1
to staff questions and participated in two meetings to assist the staff in performing an expedious. review.
(4) ht applicable i
(5)
Noi, applicable l
(6)
Not applicable L
l (7)
Not applicable b
Overall Rating:'
1
-