ML19271F256
| ML19271F256 | |
| Person / Time | |
|---|---|
| Site: | Catawba, Harris, Wolf Creek, Byron, Seabrook, Diablo Canyon, Callaway, South Texas, Comanche Peak, 05000000 |
| Issue date: | 06/20/1984 |
| From: | Eisenhut D Office of Nuclear Reactor Regulation |
| To: | Gilinsky, Palladino, Roberts NRC COMMISSION (OCM) |
| Shared Package | |
| ML19271F257 | List: |
| References | |
| TASK-AS, TASK-BN84-104 BN-84-104, NUDOCS 8406220093 | |
| Download: ML19271F256 (6) | |
Text
Central Files ONLY r
Docket No. 50-483 June 20,1984 MEMORANDUM FOR:
Chairman Palladino Conmissioner Gilinsky Commissioner Roberts Commissioner Asselstine Commissioner Bernthal FROM:
Darrell G. Eisenhut, Director Division of Licensing
SUBJECT:
WESTINGHOUSE ECCS ACTUATION LOGIC REVIEW BOARD NOTIFICATION 84-104 In accordance with the NRC procedures for Board Notification, the following information is being provided directly to the Commissior. The appropriate Boards and Parties are being i,1 formed by cony of this memorandum. This information is applicable to Callaway, which is currently before the Commission. The appropriatt Boards and parties are being informed by copy of this memorandum.
Board Notification 83-151 discussed a Wutinghouse ECCS Actuation logic concern. Board Notification 84 038 provided an update of the staff review of this item. This Board Notification provides the final results of the staff review. The staff finds that the current Westinghouse logic of ECCS actuation on low pressurizer pressure only affords the greatest protection against TMI-2 type events. The enclosei Mattson Lo Eisenhut memo of April 18,1984 provides the details of the staff evaluation.
ff fj arrell G. Eisenhut, Director Division of Licensing Office of Nuclear Reactor Regulation
Enclosure:
As Stated cc: See Next Page
- Previous concurrences concurred on by:
DL DL RPurple for RStark:mj DGEisenhut 5/17/84 5/21/84 8406220093
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UNITED STATES M
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NUCLEAR REGULATORY COMMISSION
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[%g+...f.i W ASHINGTON, D. C. 20555 APR 181984 MEMORANDUM FOR: 9 DIFre'l FG'.*JEi s enh'Ot,'? Di re~cto r' Division ~ of Licensing FROM:
Roger J. Mattson, Director Division of Systems Integration
SUBJECT:
BOARD NOTIFICATION OF FINAL EVALUATION OF REVISED ECCS ACTUATION LOGIC IN THE BORSSELE NUCLEAR POWER PLANT
Reference:
(1) Memorandum, Mattson to Eisenhut, " Board Notification" dated Captember 26, 1983.
(2) Memorandum, Mattson to Eisenhut, " Board Notification Followup" dated January 23, 1984.
(3) Letter, J. J. Sheppard (CP&L) to D. G. Eisenhut, 0G-114 dated February 17, 1984.
(4) Letter, P. Dozinel (Tractionel) to D. G. Eisenhut, dated March 13, 1984.
In reference (1), I requested you notify all hearing boards associated with Westinghouse designed PWRs of a revision made to the ECCS agtuat, ion logic in the Borssele Nuclear Power Plant.
I also stated in reference (1) that our intent was to ask % Westinghouse Owners Group to voluntarily evaluate the relative benefits / detriments of the Borssele revision.
In reference (2), I provided you with an update of the owners group evaluation status.
The Westinghouse owners group responded to our request in the reference (3) letter.
Their respcose evaluated the Borssele ECCS logic revision and concluded that because of inherent design differences between the Borssele plant and Westinghouse-designed plants in the U.S., the logic revision should not be made to U.S. Westinghouse Plants.
Mr. P. Dozinel of Tractionel (The Borssele plant operator) also offered us an unsolicited evaluation (reference 4) of the applicability of their ECCS logic revision to Westinghouse designed U.S. plants.
~" 4cA p
cf
D. G. Eisenhut
- 1g Mr. Dozinel's evaluation also concluded that inherent design differences led him to recommend that the Borssele revisions not be incorporated in Westinghouse designed U. S. plants.
The staif has reviewed references (3) and (4), and we c~oncur in' their evaluations and conclusions. We believe that the current Westinghouse logic of ECCS actudtion on low pressurizer pressure only affords the greatest protection against TMI-2 type events. We also believe that the current efforts on improving the steam generator tube rupture (SGTR) guidelines, combined with efforts to improve reactor coolant pump trip (RCP) criteria so the RCPs wiil remain running for most SGTR events, will significantly improve the plants response to ECCS actuation on SGTR.
We have enclosed references (3).and (4), which we recommend accompany the board notification.
I have also enclosed proposed responses to Messrs. P. Dozinel and J. Sheppard thanking them for their evaluation.
l i
Rogef'J.
ttson, Director
. Division of Systems Integration cc:
H. Denton E. Case T. Speis H. Thompson R. Vollmer D. Ross, RES L. Rubenstein D. Muller RSB S/L's P. Boehnert, ACRS 6
DISTRIBUliON LIST FOR BOARD NOTIFICATION Byron Units 1&2, Docket Nos. 50-454/455 Gary W. Holmes, Esq.
Catawba Units 1&2, Docket Nos. 50-413/414 Dr. Frank F. Hooper Comanche Peak Units 1&2, Docket Nos. 50-445/446 Helen Hoyt, Esq.
Diablo Canyon Units 1&2, Docket Nos. 50-275/323 Mr. Richard B. Hutbard Seabrook Units 1&2, Docket Nos. 50-443/444 Sen. Gordon J. Humphrey Shearon Harris Units 1&2, Docket Nos. 50-400/401 Mrs. Phillip B. Johnson South Texas Units 1&2, Dccket Nos. 50-492/499 Dr. W. Reed Johnson Wolf Creek Unit 1, Docket No. 50-482 Bradley W. Jones, Esq.
Richard E. Jones, Esq.
Dr. Walter H. Jordan Atomic Safety and Licensing Dr. Richard F. Cole William S. Jordan, III, Esq.
Board Panel Mr. John T. Collins James L. Kelley, Esq.
Atomic Safety and Licensing Mr. Nicholas J. Costello Janice E. Kerr, Esq.
Appeal Panel Philip A. Crane, Jr., Esq.
Dr. J,.rry Kline Brentwood Board of Selectmen Charles Cross, Esq.
Christine N. Kohi, EN.
Dr. James C. Lamb, III Division of Consumer Counsel Edward L. rmcc, Jr.
c/o Mr. Barry S. Zitser Mr. James E. Cummins Dr. Robert M. Lazo Docketing and Service Section Thomas G. Dignan, Jr., Esq. Dr. Linda Little Documelt Management Branch Mr. John F. Doherty Ms. Karen E. Long Palmetto Alliance Ms. Jane Doughty Dr. Emmeth A. Luebke Region III, U.S.N.R.C Mr. Owen B. Durgin Mr. Angie Mechiros Town Manager's Office Kim Eastman Morton B. Margulies, Esq.
Town Hall - Friend Street Wells Eddleman Mr. John Marrs Town of North Hampton Gary J. Edles, Esq.
Dr. Kenneth A. McCollom Eric A. Eisen, Esq.
J. Michael McGarry, III, Esq.
Phillip Ahrens, Esq.
Mr. Frederick Eissler Mr. Patrick J. McKeon Dr. George C. Anderson Mrs. Juanita Ellis Mr. Edward F. Meany Mrs. Elizabeth Apfelberg David S. Fleischaker, Esq.
Michael Miller, Esq.
Maurice Axelrad, Esq.
Mrs. Raye Fleming Ruthanne G. Miller, Esq.
Robert A. Backus, Esq.
Dr. Harry Foreman Thomas S. Moore, Esq.
Charles Bechhnefer, Esq.
Dr. Richard F. Foster Ms. Pat Morrison Brian Berwick, Esq.
R. K. Gad III, Esq.
Jack R. Newman, Esq.
Mr. Richard E. Blankenburg Joseph Gallo, Esq.
Mr. H. Daniel Nix Peter B. Bloch, Esq.
Billie Pirner Garde Bruce Norton, Esq.
Mr. Glenn 0. Bright Ms. Sandra Gavutis Dr. Hugh C. Paxton Mr. William L. Brown Arthur C. Gehr Esq.
Mr. Travis Payne, Esq.
Mrs. Peggy Buchorn Ellen Ginsberg, Esq.
Spence Perry, Esq.
Dr. John H. Buck Dr. Reginald L. Gotchy C. Edward Peterson, Esq.
Dr. A. Dixon Callihan Herbert Grossman, Esq.
Ms. Roberta C. Pevear Mr. Calvin A. Canney Mr. Robert P. Gruber William L. Porter, Esq.
Dr. James H. Carpenter Robert Guild, Esq.
Mr. David Prestemon Doug Cassel, Esq.
Mr. Lee M. Gustafson Sen. Robert L. Preston Brian P. Cassidy Esq.
Dr. Jerry Harbour Dr. Paul W. Purdom Mr. A. Scott Cauger Mr. Thomas H. Harris Ms. Diana P. Randall Ms. Diane Chavez Mr. R.obert J. Harrison Mr. Daniel F. Read Mr. Donald E. Chick Donald L. Herzberger, MD Joel R. Reynolds, Esq.
Ms. Wanda Christy Renea Hicks, Esq.
Nicholas S. Reynolds, Esq.
Mr. Mendall Clari:
Mr. Ernest E. Hill Mr. Jesse L. Riley John Clewett, Esq.
Ms. Beverly Hollingworth Anthony Z. Roismari, Esq.
DISTRIBUTION LIST FOR BOARD NOTIFICATION Byron Units 1&2, Docket Nos. 50-454/455 Catawba Units 1&2, Docket Nos. 50-413/414 Comanche Peak Units 1&2, Docket Nos. 50-445/446 Diablo Canyon Units 1&2, Docket Nos. 50-275/323 Seabrook Units 1&2, Docket Nos. 50-443/444 Shearon Harris Units 1&2, Docket Nos. 50-400/401 South Texas Units 1&2, Docket Nos. 50-498/499 Wolf Creek Unit 1, Docket No. 50-482 Alan S. Rosenthal, Esq.
ACRS Members Mr. John Runkle Vr. Rober : C. Axtmann Ms. Mary Ellen Salava Mr. Myer Bender Mr. Alfred Sargent Dr. Max W. Carbon Mr. James 0. Schuyler Mr. Jesse C. Ebersole Melbert Schwarz, Jr., Esq.
Mr. Harold Etherington Mr. Lewis Shollenberger Dr. William Kerr Ms. Jo Ann Shotwell Dr. Harold W. Lewis Jay E. Silberg, Esq.
Dr. J. Carson Mark Mr. Gordon Silver Mr. William M. Mathis John M. Simpson, Esq.
Dr. Dade W. Moeller Mr. Lanny Alan Sinkin Dr. David Okrent Ivan W. Smith, Esq.
Dr. Milcon S. Plesset Carol S. Sneider, Esq.
Mr. Jeremiah J. Ray Mr. Micnael D. Spence Dr. Paul C. Shewmon Mr. Michael J. Strumwasser Dr. Chester P. Siess George F. Trowbridge, Esq.
Mr. David A. Ward Dr. Mauray Tye Paul C. Valentine, Esq.
Ms. Anne Verge Dr. Bruce Von Zellen Mr. Howard A. Wilber Mr. Donald R. Willard Mr. Harry M. Willis Richard P. Wilson, Esq.
Richard D. Wilson, M.D.
John F. Wolf, Esq.
Sheldon J. Wolfe, Esq.
Robert A. Wooldridge
/
Board Notification 84-104 Branch service list of addressees receiving material on the following dockets:
BYRON DOCKET Mr. Dennis L. Farrar Mr. William Kortier Mr. Michael Miller, Esq.
Mr. Edward R. Crass Mr. Julian Hinds
, CATAWBA DOCKET Mr. H. B. Tucker North Carolina MPA-1 Mr. F. J. Twogood Mr. J. C. Plunkett, Jr.
Mr. Pierce K. Skinner North Carolina Electric Mechership Corp.
Saluda River Electric Cooperative, Inc.
Mr. Peter K. VanDoorn Regional Administrator, Region II Spence Perry, Esq.
Mark S. Calvert, Esq.
COMANCHE PEAK DOCKET Mr. Homer C. Schmidt Mr. H. R. Rock Mr. A. T. Parker William A. Burchette, Esq.
Mr. David R. Pigott, Esq.
Mrs. Nancy H. Williams DIABLO CANYON DOCKET Mr. Malcolm H. Furbush Mr. Lee M. Gustafson Resident Inspector /Diablo Canyon NPS Dr. Jose Roesset Dr. William E. Cooper Mr. W. C. Gangloff Regional Administrator, Region V Board Notification 84-104 Branch service list of addressees receiving material on the following dockets:
SEABROOK DOCKET Bruce Beckley D. Pierre G. Cameron, Jr., Esq.
Regional Administrator, Region I E. Tupper Kinder, Esq.
Resident Inspector Mr. John DeVincentis Mr. A. M. Ebner Mr. Stephen D. Floyd Ms. Letty Hett Honorable Richard E. sullivan Scacoast Anti-Pollution League SHEAR 0NHARRISDOCKE[
Mr. E. E. Utley Mr. David Gordon, Esq.
Mr. Thomas S. Erwin, Esq.
Resident Inspector Charles D. Barham, Jr., Esq.
Mr., George Jackson Regional Administrator, Region II Mr. Robert P. Gruber SOUTH TEXAS [0CKET Mr. G. W. Oprea, Jr.
Mr. J. H. Goldberg Mr. D. G. Barker Mr. E. R. Brooks Mr. H. L. Peterson Mr. J. B. Poston Resident Inspector Mr. Jonathan Davis Ms. Pat Coy Mr. Mark R. Wisenburg Mr. Charles Halligan Regional Administrator, Region IV WOLF CREEK DOCKET Mr. Gienn L. Koester Mr. Nicholas A. Petrick Mr. Donald T. McPhee Resident Inspector Teri Sculley Regional Administrator, Region IV Mr. Joe Mulholland Regional Administrator, Region III
't Cp&L Casolina Poweir 6 Uchi Com;nny February 17. 19U, Hr. Darrell G. Eisenhut, Director Division of Licensing, HRR Huclear F,egulatory Comission Washington, DC 20555
Dear Hr. Eisenhut:
The Westinghouse hners Group (WOG) and Westinghouse t ave carefully evaluated your letter of Hovember 15, 1983, and the pr oprietary rept on the Borse11e reactor.
On the' basis of this review, the WOG and Westinghouse have determined that coincident signals of low pressurizer pressure aid icw pressuriter level for initiation of SI should not be reinstated in Westinghouse The reasons for this conclusion are as fol' ows:
reactors.
The arguments advanced f ar reinstating the coinc;dnt signal icgic 1.
in the Borse11e reactor are not directly relevan. to Westingho wa reactors because of inherent differences in desiqn.
a,) Coincident signal logic would not prevent SI actuation for Westinghouse reactors following tube failurc; which are sufficiently large to cause reactor trip on low pressurize >
Forsmallerfailures,anormalpihntshutdownir pressure.
possible which would prevent SI actuation,.wlithout use of coincident logic, and would also avnid an unnecessary reat'r trip.
b,) Automatic protection for a steam generator tube rupture WfR) is arovided in the Borse11e reactor. This includes reactu trip on ligh radiation in a : team line, trip of tne turbine aft.n a prescribed.. orval, and automatic initiation of chemical.md volume control system (CVCS) auxiliary spray Westinghee:,
r from an SGTh reactors depend ;. operator action to recove
- svent, Manual response to SGTR events is pr eferred, as discussed below.
c.) Actuation of the automatic protection syste on high secenary side activity may lead to reactor trip foil wing small tup As toted above, a leaks which wculd otherwise not occur.
controlled plant shutdown may be beneficial for such ever::.
In addition, actuation of an automatic protectLon systec duri events other than steam generator tube failyres, such as spurious high radfation eiem, or multiple ?ailure event, adversely impret clant safety and availabti)ty.
n 1508g:12
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g OG-il4 Mr. Darrell G. Eisenhut February 17, 1984 d.) Although coincident signal logic in combi,ation with an automatic protection system similar to that in the Borselle Reactor design may prevent 51 actuation for smaller tube failure events, it would not prevent SI actuation for larger tube failures in Westinghouse reactors, such as the Ginna incident.
Hence, manual actions would still be required for eYent diagnosis and $1 termination, Since the larg 3r tube failures are of most concern, the coincident signal logic and automatic protection syste:n would be of little benef f t.
e.) The Borselle reactor has special design featur'.es to limit tL thermal stresses associated with -injecting CV 5 auxiliary spray into the pressurizer. Westinghouse plants do not ha/e these features and use of CVC5 auxiliary spray for eactor coolant system (RCS) depressurization causes high the' mal stresses ir, the pressurizer nozzles.
For this reason CVC) au'xiliary spray of pressurizer power operated relief valYes (PORVs)) pray and use is the third alternative (after normal pressu izer s for RCS depressurization in a Westinghouse reactor.
f.) An SI signal aoparently trips power to the re ictor coolant pumps (RCPs) in the Borse!1e reactor (p. 6 of report). The desire to maintain forced circulation is one of the reasons ciced for wanting to reinstate coincident signals for' S I.
An 51 signsi does not trip the RCPs in Westinghouse reacto s.
g.) The concerns expressed about depleting the co 1 tents of the HPSI storage tanks (pp 8 & 10) apparently stem fro n having tanks' of
- limited capacity in Borse11e.
In contrast, tie espacity of the refueling water storage tank, wnich is the so rce of SI water in a Westinghouse reactor, is many times greater tnan the amount of
$1 needed during an SGTR.
2.
Reinstatement of the former coincident signals fo* initiating Si in Westinghouse plants would degrade the protectiori against a stuck-open PORY without improving the ability of aperators to respond to SGTRs.
This was the reason for changi 1g from the coincident logic after the THE event.
It is consistant with the WOG and HRC operating p1ilosophy, which emphasizes core cooling under all conditions, to rely on manual actions to terminate Si after proper diagnosis of an SGTR event.
rather than to assume manual actuation of 31 as protection agsis t a pressuri:er steam space break.
1508g: 12
A 0G-114 Mr. Darrell 0. Eisenhut February 17, 1%4 It is noted that there is an anomaly for the vapo space break u
there is a reliance on manual operator action to initiate SI although the stated operating piilosophy for Borse11e is to no'. take destinghouse !. a manual operator action in the first 20 minutes, the WOG cannot agree with such a philosopny that.emphasizes onc accident condition over another and is highly prescriptive to c specific transient.
In addition, there seems to be little or r.;
consideratica in the proposed Borse11e recovery strategy for multiple events, or failures, which are an integr'ai part of the W3G emergency response guidelines (ERGS) development program.
An improved version (Rev.1) of the ERGS for responding to an SCTR has recently been corr:pleted and will soon be inecrporated intoTt:ne plant-specific emergency procedures at Westinghouse plants.
ERGS incorporate lessons learned from the Ginna f4TR and have Wn extensively reviewed by the WOG and validated on the Seabrcok simulator. The ERGS describe operator actions t4 respond to sny of the specific concerns expressed in the Borselle report.
Recovery actions are presented in two phases.
In the first pbne, operator actions are directed toward equalizing primary and afected steam generator pressure and terminating SI to s :op primary-to-secondary leakage.
At the completion of this first phase, rein ses from the affected steam generator would have ste sped and all irnmediate safety concerns would be resolved. Th e second. phase of the recovery cools and depressurizes both the RC E and affected steam generator to cold shutdown conditions.
Three al:ternative meth ds.
are described in the ERGS for completing this phpse. The cooldun to cold shutdown is unaffected by coincident signal SI actuatiw logic or prior actuation of SI.
Pressure in the affected ste w intact steam generator would remain greater than.that in the This is a necessary generators since it would have been isolated.
condition to maintain subcooling in the reactor scolant system.
It is not clear with the information presented whether er not the recovery strategy proposed for Borse11e could meintain the
'subcooling margin ne:essary to avoid SI initiati on.
Recent analysis work sponsored by the WOG nas loentu ma cr ue IF*
by which operators can distinguish between an SCTR and a smal14reak SGTR and mann H y 1.0CA, such that RCPs will be kept running for at tripped for a LOCa.
One r(7 ort describing thest analyses has
+n transmitted tc the ItRC and a second report will be transmittu Plant specific procedbees containing these o sr b within 30 days.
for keeping RCPs in operation during an SGTR wi'l soon be in
- ct.
50Sg:12
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OG-114 February 17. N 4 4-Hr. Darrell-G. Eisenhut It is our conclusion that there is no benefit to be gaifed by restorc:n of the low pressurizer pressure - low pressurizer level coincident ection in Westinghouse-supplied signal for initiation of safety ina We trust that this letter answers the specific reactors in the U.S.
as sufficient question asked in your letter of Hovember 15 and providconclusion.
background information to enable you to concur with our Very truly yours,
',"[=+-
J. J. Sheppard, Chaimar Westinghouse Nner s Group cc: WOC Reps Analysis,5/C g e$ ) g /,_ Q ;/-
Procedures S/C M
H. Y. Julian y
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B. Honty R, Suman E. Volpenhien 150Sg:12 j
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Tractione j
.p" Formerty 78,l_ ?g (,L a Societe de Traction et d' Electric:te
't tractionel s.
Your ref.
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Out ref. 739618011 Director Dtvision of Licensing INRR P
P DM Nuclear Regulatory Commission Tel. direct 02/234. 4 7. 6 6 Washington DC 20 555 Standard 02/234 4111 17026 Brussels, March 13th 1984 M
Dear Mister Eisenhut,
f As a representative of the belgian utilities to the Westinghouse Owners' Group I have received a copy of your letter of November 15 1983 relating to the approach introduced in the Borselle reactor to cope with a SGTR accident.
After having seen both a stuck PORV incident an,d a, SGTR in PWR's of Westinghouse design it is our strong celief that the SI initiation by a coincidence between low pressure and low pressurizer level should not be reintroduced and that SI should be initiated by a low pressure signal only.
I hereto attach a note supporting this position.
as Yours sincerely T RA C T I ON E L s
9V C C,.:,
P.
DOZINEL
=
ggggggh Deputy Manager CF
~
t unctiones L
s A.
INTRODUCTION Most operating systens were conceived before the TMI event.
This event has clearly changed the emphasis from le ge LOCA's to anticipated and abnormal plant transients and required some changes in the reactor protection systems
( TMI action plan ).
The recommended changes depend largely on the basic protection concepts which differ widely for different reactor vendors.
B.
KWU versus Westinghouse design concept.
Some very important differencer in the design concept exist between KWU and Westinghouse plants especially for addressing small LOCA's ( inclusive SGTR ) such as :
W designed plants have two distinct containment isolation phases called A and B depending on the cont'ainment pressure.
For a given containment pressure treshold ( typically 10 %
of design pressure )
isolation phase A is triggered upon generation of a SI signal.
In this phase some vital contzel systems continue to function and enable the operator to control the plant to achieve and maintain a safe shut down :
by means of e.g : CVCS systems ( + pressurizer spray )
primary coolant pumps which keep running
- containment pressurized air available for pneumatic operated valves.
- component cooling remains available.
And those are the systems used to mitigate the consequences of small loca's and abnormal plant transitions.
Only when the containment prensure reaches the treshold of 50 %
isolation phase B is reached wherein operator looses control of many systems and the programmed large LOCA sequence takes over.
2 -
The KWU designed plants have only 1 isolation phase which corresponds to the B phase for Westinghouse plants and which is triggered by a SI signal.
This is the main reason why a SI sigr;41 generation in case of small LOCA's should be avoided !
KWU plants but not in Westinghouse plants.
l l
Westinghouse plants generally have much smaller pressurisers for a given power rating than equivalent KWU re,ctors.
Hence for many small break loca's or SGTR the low level treshold is not reached in KWU reactors and only larger breaks which need high pressure safety injection
, may lead to emptying the pressurizer.
Westinghouse plants are not equipped with N - 16 detectors on the steam lines and are not programmed to start an automatic depressurization sequence when a SGTR occurs as is the case for KWU reactors.
This feature in KWU reactors starts initigating the consequences of a SGTR very early and can reduce the loss of coolant such that a high capacity SI injection may not be needed and that a CV,CS system can maintain a high RCS inventory.
For Westinghouse designed plants a turbine trip follows immediately upon reactor scram.
For KWU plants a delay of 20 seconds is built in to extract a large amount of heat from the RCS ensuring a sufficient degree of subcocling during the depressurzation following a SGTR.
For Westinghouse plants, the subcocling has to be achieved by MPSI ( preferably 17, conjunction with pressurizer spray )
combined with steam d!scharge from the intact steam generator once the faulted stear. generator is identified.
- These differences are illustrated in table 1 by comparing a SGTR scenario in KWU and Westinghouse plants.
C.
Impact of application of the low pressurizer pressure-low pressurizer level coincidence trip in Westinghouse reactors In our pisnts
,'fo,r sany,small break loca transients l'ow pressurizer level - low the application of a pressurizer pressure coincidence trip will hardly change anything.
Because of the smaller pressurizer size the low pressurizer level setpoint will be reached before the low pressurizer pressure setpoint for SI generation is reached ( ef events in Ginns, Doel ref paper by E.
STUBBE and H.
MICHIELS presented at the Jackson Wyoming conference Sept 83 fig. 4 attached ).
However many reactor transicnts have identified unreliable level readings ( ef Doel )
because the level signal derived from adP cell is calibrated only for nominal water conditions ( densities ) and cannot be used when the pressurizer conditions deviate from nominal conditions during a transient,(
e.g.
by filling up with cold HPSI water combined with spray ).
Furthermore in case of a large LOCA (
e.g.
rupture of surge-line--) whereby one level reading column may be destroyed the design of the level reading cell should then be such as to indicate low level in order to trigger SI signal.
The application of the coincidence trip is specially intended to cop':
'ith smaller loca's or steamgenerator tube ruptures in KWU reactors.
These transients are by nature slow tran'sients which allow sufficient time for judicious operator intervention.
However the plant should be sufficiently protected for larger LOCA's which need automatic SI injection.
Hence any change in trip setting for SI injection to accomodate slow transients should not compromise the response to faster transients.
This would require additional changes in the trip levels or operating procedures (
e.g.
reducing the containment pressure treshold for containment isolation ) in such cases as vapor space breaks ( stuck open PORV). which are accomoanied hv a hinh ne*==n*4ca*
1awal
D.
CONCLU3 ION The above argume.nts should strenghten the position not to apply the KWU fix i.e.
not to restore the low pressurizer pressure - low pressurizer level coincidence trip in Westinghouse reactors.
e e
TABLE 1 : Typical scenario for a single tube SGTR event.'
Sequence of main evente KWU original concept Westinghouse concept Detection of the event Automatic by N16 sensors
- High radiation alarm after about 15 seconds in air ejectors
- blowdown sampling after about 60 seconds Initial depressurization Preprogrammed ( fast )
by loss of RCS coolant of the RCS
( slow )
Reactor scram by N 16 sensors (15 see) by low pressurizer pressure
( after about 300 sec ).
Turbine trip 20 sec. after reactor by reactor scram scram Pressurizer level slow ( co=penated by fast, due to small size decrease CVCS ) for large pressu-pressurizer empties in about rizer 300 sec.
Safety injection signal does not occur by using on low pressurizer pressure coincidence trip logic
( after About 400 sec. )
RCS cooldown CVCS injection + steam HPSI + steam discharge from discharge from intact identified intact SG.
SG Make-Up of RCS coolant CVCS only HPSI + pressurizer spray Pressure egalisation preprogrammed by tripping the HPSI across break
( operator ) after about 600 seconds.
x The time delays are only indicative to illustrate the chrenology of the events.
PREPRINT OF PAPER TO BE PRESENTED AT THE ANS TOPICAL MEETING ON ANTICIPATED AND ABNORMAL PLANT TRANSIENT IN LIGHT WATER REACTORS SEPTEMBER 26-29, 1983/ JACKSON, WYOMING BY E.J. STUBBE TRACTIONEL H.SABLON E.B.E.S.
ANALYSIS AND SIMULATION OF TEE DOEL-2 STEAM GENERATOR TUBE RUPTU EVENT
- 1 E.J. STUBBE, J.M. CHALANT : TRACTIONEL, Brussels H. MICHIELS, H. SABLON : E.B.E.S.,.Jel ABSTRACT Severe plant transients, following a steam generator tube rupture (SGTR), have a relatively high probability of occurrence and may entrain a certain risk to che population and the plant (class IV accident).. The SGTR event which occurred at the DOEL-2 plant in June 1979, presents many interesting phenomena which are analysed based on the on-site data recordings on one hand, and a detailed numerical simulation, using the RELAP-5 code, on the other hand.
This event stimulated a revision of the emergency procedures, led to considerable i=provements in the operator control over safa-guard systems and highlights the i=portance of operator training.
The numerical results do enhance the understanding of the cbserved phenomena and complement the plant recorded data.
The RELAP-5 code is capable of simulating such transient.
- 1. INTRODUCTION Severe plant trausients, following a SGTR have been cbserved in several power plants (ref. 1) and may occur with a relative high probability due to serious steam generator tube degradation.
Since this event is a class IV accident which breaches several protective barriers of the plant, there is a certain risk involved for the po-pulation.
Furthermore, plant experience has learned that a difficult decision making process is required at almost every phase of such transient to maintain the power plant under full control.
The SGTR event that occurred at the DOEL-2 power plant (2 loop 392 MWe PWR) illustrates the different phases which have been mastered as prescribed and which affected neither the environment nor the installation.
2.
The ahatomy of the transient presented in chapter 2 is based on the on-site data recordings and a detailed numerical simulation of the transient by means of the computer code RELAP-5 MOD 1.
The impact of this event en the emergency procedures and on some system con-trols is discussed in chapter 3.
- 2. ANATOMY OF THE DOEL-2 SGTR EVENT 2.1. Chronology of the events and operator actions Figure 1 illustrates the evolution of the most important pdrameters as reconstructed from the plant recordings.
The plant was at the end of the heat-up phase following a cold shut-
~
down of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with the reactor suberitical (Decay heat : 6 MWth),
both primary pu=ps ruuning (2 x 2.5 MWth) and both steam generators (SG) isolated (MSIV closed).
- Initiating event : figure 1 between points A and D At 19.20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> on June 29th 1979, a quick level decrease in the pressurizer and a pressure decrease of 2.5 bar/ min in the RCS was observed. While the pressurirer level went off-scale low (B), a quick level increase was observed in the B-loop SG (C).
When the automatic measurement channels of the SG blowdown loops recorded a maximum activity level, the operator diagnosed within a few minutes the cause of the event to be a SGTR in the B-loop SG.
- Mitigation phase : figure 1 between points D and L start-up cf a third charging pump to maximize water inventory
. opening of the intact SG A atmospheric steam dump valve (D)
. the operator tripped the primary pump of affected loop
. at 117 bar, the safety injection signal was generated which initiated the high pressure safety injection (HPSI) at 105 bar low level in SG A (G) actuated the steam valves of both SG to the turbopump which starts injecting AFW (H).
The steam dis-charge from the affected SG B is stopped 8 min. later (I).
to reduce the break flow rate, the operator restarted the prima-ry pump of affected loop and utilized full pressurizer spray (J).
This operation was stopped when the pressurizer level went off-scale high (K).
This caused the primary pressure to increase from 75 bar to the shutoff head of the RPSI (L).
- Safety injection cancelling phase : figure 2 between points L a".1 R
the operator tried to cancel the SI-signal in order to reduce further the primary pressure.
A pressure reduction was needed to reduce the break = ass flow rate, to avoid activating the safety valves of the affected SG and be able to switch to the shutdown cooling system (below 28 bar).
However, a circuit logic fault did regenerate an SI signal after reset.
About 20 min. elapsed before the concerned bistables were flicked over manually and 3 HPSI pumps were stcpped (M).
3.
after checking the subcooling margin the last EPSI pump was stopped (N) and pressure dropped to 65 bar (0).
the containment isolation, generated by the SI-signal, elimina-ted the compressed air supply in the reactor building, hence preventing to open the let-down line.
About 20 min, elapsed before the air supply was restored and the pneumatic isolation valve on the letdown line was opened (P).
. after stopping a charging pu=p (Q), the pressure decreased to the point where the residual heat removal system can be coupled to the RCS (R).
- Long term behaviour : about 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> after the break occurred the temperature in the steam phase of the affected SG was still 180*C, which prevented a reduction of the primary pressure below 10 bar to avoid a dilution risk. To further avoid flooding of the main steam line and to eliminate any risk of sudden steam collapse on the hot steam-cold water interface, nitrogen was injected in the steam line, while draining water through a drainline into a li-quid waste reservoir.
2.2. Numerical simulation of the transient 2.2.1. gbjectives A thermal hydraulic analysis of this event was performed by means of the computer code RELAP-5 mod 1 CYCLE 14 (ref. 2) with the fol-lowing objectives
- to improve, by numerical means, the understanding of the different phcnemena occurring during such event and the interpretation of the verious recorded data
- to evaluate the mass and energy balance at various stages during the transient and the evolution of the coolant inventory in the RCS
- to evaluate the break flow rate, and the radioactive releases to the atmosphere from the faulted SG
- to assess the capability of the RELAP-5 code and their users to simulate such transients, and thereby dispose of a qualified nume-rical tool to evaluate the i= pact of operator actions en the transient.
2. 2. 2. N_o_d_a_l_i_s_at_io__n The simulation period of 2700 s, started at the estimated time of tube rupture (to = 19 hr 20 min. : fj7. 1, point A) and ended at the pressure recovery after stopping the pressurizer spray (fig.
1, point L).
The final nodalisation, including SG secondary, consists of 136 volumes, 140 junctions and 145 heat slabs.
Some special models were it orporated such as :
- steam generator tube break model : A valve junction, between SG B primary and secondary was simulated with a control valve adjusted to yield the recorded initial level rise in the affected SG (fig. 1 e)
- auxiliary feedwater systems : Two motordriven pumps and one ter-bine driven feedwater pump were simulated (control block)
- charging and let-down system
- pressurizer spray and heaters : The spray system had to be simu:a-ted by separate sprty lines to each pressurizer volu=e in crder to overcome water hang-up in the pressurizer caused by too high in-terface drag.
- high pressure safety injection system : Four pumps delivering 50 %
to the downcomer and 25 % each to both cold legs were si=ulated by 3 time-dependent junctions with tabulated flow delivery curves in function of a compensated RCS backpressure.
- steam generator atmospheric steam du=p valve Figure 2 illustrates the activation sequence of the various systems.
2.2.3. Discussion _of the_ numerical _results The fign. 3 to 7 illustrate the comparison between calculated data (RELAP : solid line) and the plant recorded data (dashed line).
- The calculated pressure evolution (fig. 3) compares favourably with the recorded data. The initial decompression follows closely the recorded values until the pressurizer is empty. At 600 s the calculated pressure drop results from excessive condensation of hot pressurizer steam on the subcooled primary fluid.
This dis-crepancy may result from a code defiency in condensation modelling but also from the condensing heat transfer reduction in the pre-sence of hydret n at the interface.
- When the EPSI is activated (lOs), the calculated pressure at which the RCS stabilizes is about 4 bar below the recorded pres-sure. This is caused by underestimating the shutoff head of the HPSI (105 bar used for safety calculations) and eventual instru-ment error
(+_1. 5 % ).
- Fig. 4 illustrates the evolutien of the collapsed water level in the pressuriser.
The discrepancies are duc, firstly to the limi-ted range for the recordings, but =ainly due to the calibration error of the level gauge beyond nominal conditions.
For the pres-suri:er conditions at 2400 s, the A P level gauge, calibrated for nominal conditions, indicates a full pressurizer, because cf the heavier weigt.t of the cold water.
By applying the necessary cor-rections for density, a 100 % level reading should correspond to a collapsed water level at 68 close to the calculated level.
5.
- Figures 5 and 6 illustrate the pressure and water level in the intact 3G.
The discrepancy in the water level is caused by under-estimating the steam discharge rate and uncertainties in the timing of the AEW motorpump for this steam generator.
2.3. Detailed analysis of some important phenomena 2.3.1. Break Fig. 7 illustrates the evolution of the calculated flow rates through the break and EPSI injection.
Initially the break flow is about 15 kg/s (3C0 gpm). Post examination of the failed tube re-vealed a longitudinal crack of about 7 cm long located in the innermost row of tubes at the beginning of the U bend. The cause is considered to be stress corrosion crac'ing enhanced by excess ovality.
2.3.2. geglag3_igvsntory_ig_3tg_ggS_1_g((yg3_g{_eggssugiggg_segar
- Although the water level in the pressurizer went off scale low (600 s), the calculatiens suggest that at no time steam void formation occurred in the loops or stagnant regions of the RCS.
Such risk was minimized by keeping at least one primary pu=p running.
- During the EPSI period between 1200 s and the stort of the pres-surizer spray, the coolant inventory was stable. Although the cold water addition from the EPSI and the charging system excee-
~
ded the break flow rate (fig. 7), the primary coolant contraction caused by a RCS cooling rate of about 1.2*C/ min, created an almost constant volumetric water inventory (fig. 4).
Hence the HPSI system was not able to refill the pressurizer.
- Although the operator tried to reduce the pressure by using the pressurizer spray the only benefit of this action was to refill the pressurizer (fig. 4, fig. 7).
This indicates the i=portance of using the pressurizer spray, and hence the importance of keeping at least one primary pump running during such event.
- The calculations indicate that, contrary to the opfr! _ of the operator,' the pressurizer did maintain a steam space. A cold calibrated level gauge could help the operator to control better the pressurizer level, since water solid conditions would occur for a reading of about 85 % on this gauge.
2.3.3. {ggldgwg_g{_3pg_gg{gapy_syssgg_agg,a!{gggg{_s3 gag _ggggga395
- From the time the steam dump valve to atmosphere opens, the intact SG acts at an efficient heat sink for the RCS.
The affected SG constitutes a heat source, except during the short time period the steam admission valves to the turbine driven pump opens aute=ati-cally. During this time period of about 7 minutes, about 1 ten of contaminated steam discharged frem the affected SG.
~
6.
- For such relative slow transients, the structural sensible heat accounts for roughly 15 Y of the net energy balance during the initial cooldown phase. Detailed simulation of the structural componer:s is hence important, especially for simulating the pressurizer behaviour.
- For the affected steam generator, there exists no efficient coo-ling mechanism. While the U tube bundle may be i=mersed in cold water leaking from the break and injected by the AFW system, the steam dome has no cooling mechanism other than therra1 conduction via steam generator shell and internals, hence creating a very strong temperature stratification, while this SG acts as a second pressurizer.
Such condition could eventually lead to sudden steam collapse if the stratification is disturbed accidentally, i
- 3. IMPACT OF THE TRANSIENT ON PROCEDURES AND PLANT CONTROL SYSTEMS 3.2.
Isolation of the affected steam generator Although the procedures did specify the isolation of the affected SG as soon as the cause is diagnosed, no check-list of actions was available.
In this event, the operator forgot to close the vapour discharge line to the turbopump which caused the only release of contaminated steam to the atmosphere
(+ 1 ton). New procedures do present a more detailed check-list.
3.2. Primary,cump control According to the operating procedures, the operator should reduce the primary pressure to a level below the safety valve setpoint of the steam generators ( e 70 bar). Since the RCS pressure was hanging up at the shutoff head of the KPSI (105 bar) the operator started tr a second pump to have full pressurizer spray capacity and hence
- .o achieve the reco= mended pressure reduction.
Fig. 3 shcws the temporary pressure drcp during pressurizer spray.
However, the benefit of such action was to refill the pressuriner (fig. 4) and not to reduce the pressure, as the pressure rose to the shutoff head of the EPSI when spray was stopped.
This event clearly illustrates the importance of the pressurizer spray in order to increase the water inventory in the RCS, and shows the advantage of keeping the primary pu=ps running in order to be able to use the pressurizer spray, rather than the PORVS.
Keeping the primary pumps running further reduces the potential of steam void formation outside the pressurizer and minimizes the risk of pressurized thermal shock in the downcomer vessel wall.
The procedures have since been changed to stop the HPSI while creating a controlled pressure reduction in the RCS by using the pressurizer spray with only the primary pump of the intact loop, or the PORVS, if the primary pumps have been shut down on an initial pressure drcp below 87 bar (cavitatien risk) or if external power is not available.
7.
3.3. Pressurizer level control This event illustrates that the normal pressurizer level gauges are unreliable when pressurizer fills up with subcooled water. This experience learned the necessity to interpret the pressurizer level reading in ecxbination with either cold calibrated gauges and more reliable prersurizer pressure and temperature readings (cfr. TMI).
Automatic EPSI is no longer activated by the normal pressurizer level gauge.
3.4. Safety injection control Although the prevailing procedures instructed the operator to suppress wanually the safety injection signal on diagnosing a SGTR, a circuit logic fault disabled the manual resetting, such that about 20 min. elapsed before the concerned bistables were forced in the resetting mode. This circuit logic has been changed and the procedures now instruct the operator to stop HPSI if the pressurizer level is within scale and the degree of subcooling is larger than 23*C.
Furthermore, generation of a SI signal automa-tically isolated the compressed air supply in the containment whereby the vital isolation valves returned to fail-closed pesi-tion (LOCA philosophy) and disabled among others the manual PORV operation, the letdown system, the cold pressurizer spray and the component cooling to the thermal shield on the primary pumps.
Since the event highlights the importance of the compressed air supply, this system now is disabled only on phase B isolation i.e.
when containment pressure reaches 50 % of the design pressure.
3.5. _ Temperature and pressure contrel of affected steam cenerator For such event, the operator was instructed to keep the pri=ary pressure slightly above the pressure of the affected SG in order to keep control of the boron concentration in the RCS and hence to avoid a dilution risk.
Furthermore, the leak rate should be mini-nized to reduce the activity release in secondary system and to prevent flooding of the main steam lines.
The only way to have any control on such situatiori, is to discharge steam to the con-densor (if available) or to the atmosphere and thereby reduce the temperature (avoid waterha=mer), the pressure (reduce leak rate),
and the water level (avoid flooding) in the affected steam genera-tor.
This procedure has been accepted by the safety authorities for such events af ter evaluation of the risk involved.
Conclusion
- i'he incident has been centrolled as prescribed e.nd has affected neither the environment nor the installatien, although the ope-rator was faced to make important decisions based on training exparience and skill.
- The procedures have been reviewed to better instruct the opera-ter on how to cope with the different situations that may occur fellowing a SGTR.
- Some plant automatic actions have been changed to have a Letter operator control on vital systems such as the HPSI and the compressed air supply.
- tlc i=portant lessons learned from this event are
. mal-tain at least one primary pump, if possible, to control the water inventory in the 2S by means of the pressurizer spray
. do not rely only on the normal pressurizer level gauge to con-trol the pressurizer water inventory in off-normal conditions.
. to maintain full control over the affected steam generator, the operator should completely isolate this un'it and operate the steam du=ps valve if conditions warrant it.
- The numerical analysis enhanced the understanding of various phe-nomena and yielded comple=entary information concerning the evo-lution of the RCS water inventory and the releases from the RCS and the SG.
- The RELAP-5 code can be used as a reliable tool to simulate such event provided the users have a thorough understanding of the code models and their limitations, and dispose of a good data base to simulate the various components and their characteristics.
A detailed simulation of the structural sensible heat is impor-tant.
REFERENCES
- 1. Analysis of steam generator tube rupture events at OCONr.,E and GINNA INPO 82-030 November 1982.
- 2. RELAP-5 MOD 1 Code Manual V.H.
RANSOM et al.
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Carolina Power & Light Company OG-114 February 17, 1984 Mr. Darrell G. Eisenhut. Director Divisio/I of Licensing, NRR Nuclear Regulatory Commission Washingto:1, DC 20555
Dear Mr. Eisenhut:
The Westinghouse Owners Group (WOG) and Westinghouse have carefully evaluated your letter of November 15, 1993, and the proprietary report on the Borse11e reactor.
On the basis of this review, the WOG and Westinohouse have determined that coincident signals of low pressurizer pressure and low pressurizer level for initiation of SI should not be reinstated in Westinghouse reactors. The reasons for this conclusion are as follows:
1.
The arguments advanced for reinstating the coincident signal logic in the Borsella reactor are not directly relevant to Westinghouse reactors because of inherent differences in design.
a.) Coincident signal logfc would not prevent SI actuation for Westinghouse reactors following tube failures which are sufficiently large to cause reactor trip on low pressurizer pressure. For smaller failures, a normal plant shutdown is possible which would prevent SI actuation, without use of coincident logic, and would also avoid an unnecessary reactor trip.
b.) Automatic protection for a steam generator tube rupture (SGTR) is provided in the Borse11e reactor. This includes reactor trip on high radiation in a steam line, trip of the turbine after a prescribed interval, and automatic initiation of chemical and volume control system (CVCS) auxiliary spray. Westinghouse reactors depend on operator action to recover from an SGTR event. Manual response to SGTR events is preferred, as disct'ssed below.
c.) Actuation of the automatic protection system on high secondary side activity may lead to reactor trip following small tube leaks which would otherwise not occur. As noted above, a controlled plant shutdown may be beneficial for such events.
In addition, actuation of an automatic protection system during events other than steam generator tube failures, such as a spurious high radiation alarm, or multiple failure event, may adversely impact plant safety and availability.
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411 Fayettevdle Street
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4-OG-114 Mr. Darrell G. Eisenhut
-2 February 17, 1984 k
d.) Although coincident signal logic in combination with an automatic protection system similar to that in the Borselle Reactor design may prevent SI actuation for smaller tube failure events, it would not prevent SI actuation for larger tube failures in Westinghouse reactors, such as the Ginna incident.
Hence, manual actions would still be required for event diagnosis and SI termination. Since the larger tube failures are of most concern, the coincident signal logic and automatic protection system would be of little benefit.
e.) The Borselle reactor has special design features to limit the thermal stresses associated with injecting CVCS auxiliary spray into the pressurizer. Westinghouse plants do not have these features and use of CYCS auxiliary spray for reactor coolant system (RCS) depressurization causes high thermal stresses in the pressurizer nozzles. For this reason CVCS auxiliary spray is the third alternative (after normal pressurizer spray and use of pressurizer power operated relief valves (PORVs)) for RCS depressurization 1. a Westinghouse reactor.
f.) An SI signal apparently trips power to the reactor coolant pumps (RCPs) in the Borse11e reactor (p. 6 of report). The desire to maintain forced circulation is one of the reasons cited for wanting to reinstate coincident signals for SI. An SI signa'.
does not trip the RCPs in Westinghouse reactors.
g.') The concerns expressed about depleting the contents of the HPSI storage tanks (pp 8 & 10) apparently stem from having tanks of limited capacity in Borse11e.
In contrast, the capacity of*the
- refueling water storage tank, which is the source of SI water in a Westinghouse reactor, is many times greater than the amount of SI needed during an SGTR.
2.
Reinstatement of the former coincident signals for initiating SI in Westinghouse plants would degrade the protection against a stuck-open PORY without improving the ability of operators to respond to SGTRs. This was the reason for changing from the coincident logic after the TMI event.
It is consistent with the WOG and NRC operating philosophy, which emphasizes core cooling under all conditions, to rely on manual actions to terminate SI after proper diagnosis of an SGTR event, rather than to assume manual actuation of SI as protection against a pressurizer steam space break.
1508'g: 12
OG-ll4 Mr. Darrell G. Eisenhut February 17, 1984 k
It is noted that there is an anomaly for the vapor space break since there is a reliance on manual operator action to initiate SI although the stated operating philosophy for Borselle is to not take manual operator action in the first 30 minutes. Westinghouse and the WDG cannot agree with such a philosophy that emphasizes one accident condition over another and is highly prescriptive to a specific transient. In addition, there seems to be little or no consideration in the proposed Borselle recovery strategy for multiple events, or failures, which are an integral part of the WOG emergency response guidelines (ERGS) development program.
An improved version (Rev. 1) of the ERGS for responding to an SGTR has recently been completed and will soon be incorporated intoThese plant-specific emergency procedures at Westinghouse plants.
ERGS incorporate lessons learned from the Ginna SGTR and have been extensively reviewed by the WOG and validated on the'Seabrook simulator.
.ne ERGS describe operator actions to respond to many of the specific concerns expressed in the Borse11e report.
Recovery actions are presented in two phases. In the first phase, operator actions are directed toward equalizing primary and affected steam grlerator pressure and terminating SI to step primary-to-
~
C-secondary leakage. At the completion of this first phase, releases from the affected steam generator would have stopped and all i'mmediate safety concerns would be resolved. The second phase of the recovery cools and depressurizes both the RCS and affected steam generator to cold shutdown conditions. Three alternative methods are described in the ERGS for completing this phase. The cooldown '
to cold shutdown is unaffected by coincident signal SI actuation logic or prior actuation of SI. Pressure in the affected steam generator would remain greater than that in the inuct steam generators since it would have been isolated. This is a necessary condition to maintain subcooling in the reactor coolant system.
It is not clea-che information presented whether or not the recovery arategy proposed for Borse11e could maintain the subcooling margin necessary to avoid SI initiation.
Recent analysis work sponsored by the WOG has identified criteria by which operators can distinguish between an SGTR and a small-break LOCA, such t. hat RCPs will be kept running for an SGTR and manually tripped for a LOCA. One report describing these analyses has been transmitted to the NRC and a second report will be transmitted Plant specific procedures containing these criteria within 30 days.
for keeping RCPs in operation during an SGTR will soon be in effect.
1508g:12
OG-114 Mr. Darrell G. Eisenhut February 17, 1984 It is our conclusion that there is no benefit to be gained by restoration of the low pressurizer pressure - low pressurizer level coincident signal for initiation of safety injection in Westinghouse-supplied reactors in the U.S.
We trust that this letter answers the specific question asked in your letter cf November 15 and provides sufficient background information to enable you to concur with our conclusion.
Very truly yours, g
J. J. Sheppard, Chairman es ng use h ers Croup ec: WOG Reps Analysis S/C Procedures S/C H. V. Julian B. Monty R. Surman E. Volpenhien C
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February 17, 1964 Mr. Darrell G. Eisenhut, Director Division of'f.fcensing, ICR Hucle:r P.cgulatory Ccasission Washington, DC 20555
Dear Mr. Eisenhut:
The Westinghouse owners Group (WCC) and Westinghouse have carefully evaluated your letter of 16ovember 15, 1983, and the proprfetary report on the Borso11e reactor.
On the basis of this review the W0G and Westinghouse have determined that coincident signals of Iow pressurizer pressure and low pressurfrer level for initiation of SI should not be reinstated in Westinghouse retetors. The rer, sons for this conclusion are,as follows:
1.
The arguments advanced for reinstating the coincident signal logic in the Borse11e reactor are not directly relevant to Westinghouse e
reactors because of inherent differences in design.
I a.)Coincidentsignallogicwouldnotbevent51octuationfor 1
Westinghouse reactors fol kwing tu
'fallures which are sufficlently large to cause reactor trfp on low pressurizer l
i pressure. For smaller faffures, e normal plant shutdown is possible which would prevent SI actuation, without use of J
coincf(ent logic, and would also avoid an unnecessary reactor trfp.
b.) Autoestic protection for a steam generator tube rupture ($GTR) is r6vfded in the Borse11e reactor. This includes reactor trip on ifgh radiation in a steam Ifne, trip of the turbine af ter a prescribed interval, and automatic initiation of chemical and volume control systen (CVCS) ausfilary spray. Westinghouse reactors depend on operator actfon to recover from an $GTR event, Manu.I response to $GTR events is preferred, as diseus ed below.
c.) Actuation of the automat te protection system on high secondary side activity may lead to reactor trip following small tube leaks which would otherwise not occur.
As noted above, a controlled plant shutdown may be benef fef al for such events.
In addition, actuation of an automatic protection system during events other than steam generator tube f ailures, such as a spurtous high radiation alars, or multiple failure event, may adversely lapact plant safety and availability.
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.p f,.s".t Mr. Barrs!.! G. Eisenhet-4 i/.g;.
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' ?> ;. 'V' d.) 1though coincident sipal logic fn combination with an
- N f,:*, satomatic protection system staller to that in the Borse11e.
s...., -
4 even't, it would r.ot prevent 51 actuation for larger ti he faf f t,'es in L':stin@cuca reactors. such.ss the Gfnra incident.
j Hence, manual octlens would still be required for e w t x
diagnists anti 51 'tcraination. 5tnce the larger tube fattures
,p are of most concern, the coincident signal logic and automatic
]
i protect.'m system would be of little benefit.
a.) The Borselta reacter has specfat design features to limit the c
. thermal stresses associate 1 tvith in#cting CYCS auxfif ary spray fnto the pressurircr. Westin$ouse plants do not have these features and use of CYC5 auxif f ary-spray fer reactor coofant systc:t (T. CST de;ressurizetten cases h13h therns1 stresses in 4
tho Orcssurfrer no::Ics. Fct this rest:n Ci'C3 auxiliary spray i
of pr ssurizer petrar operated rettef valves (PORYs)) pray is t.e third alternative tarter nsreal. pressurizer s for RCS 79 depressurftstion. in a Westinghouse reactor.
j ce, f.) An 5! sipal ap;:erently trips power to the reactor coofant pumps
, f.., );;p?
't:
(RCPs) in the Borsello reactor (p. 4 of report). The de'.fre te t?,
saintain forced ctreuf ation is ene of the rest..,s cited 4 -
4.c J. ". ~
c1 wanting to refn: tate coincident signals for $1. An 51 signet g.y :j.
p
.does not trfp the RCPs in Westinghouse reactors.
n i
... ', g.) The concerns expressed about depleting the contents of the HP$!
((
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~
storage tanks (pp 8 & 10) apparently stes from having tanks of c'.. b-Ifmited capacity in Forsef fe. In contrast, the c4pacitl* of the
/
refueling water storage tank, which is the source of $1 water la a Westinpouce reacter, is many times greater than the amount of 5! needed during an SGTR.
q
- 2.
Reinstatement of the forcer coincident sipals for initiating $! in Westinghouse plants would degrade the protection against a
~s stuck-open PORY without improving the ability of operators te respond to SGTRs. This was the reason for changing from the o
coincident logic af ter the TN! event.
it fs consisteat wIth the WaQ and NRC operating phi 1osophy, eich esphastres core cooling under all conditicns to rely on manual h
actions to terminate 51 after proper disposIs of an $GTR event, rather than to assume manual actuation of 51 as protectton agafast a pressurfter steam space break.
I a
4 0G-114 l
MP, Darrel1 G. Eisenest
.3-February 17, 1964 4
4
("
ft is noted that there is en anosafy for the vapor space brest since there is a reif ance on manual operator actfon to initiste 51 although the stated operating philosophy for Sorselle is to act take 5
sanual operator action 8e the first 30 minutes. Westfr$ouse and the WOG cannot agree with such a philosophy that emphas1rer one accfdent condition over another and f s highly prescripthe to e specf f fc transfent. In additfon, there seems to 'we little or as i
consideration in the preposed torselle recovery strategy for suittpie events, or failures. whirh are an integral part of the WOG amargency response guidelines (ERGS) development progreg.
An iaproved versfon (Rev.1) of the ERGS for cesponding to at. SGR has recently been ccepteted and % fit soon be 'ncorporated into
' plant-speciffe e crgency procedwes at Westfrghouse plants. These t
ems incorporate lessons lectned free the Gfona %iR and kave been t
t:stensively reviewed by the WOG and validated.on the f.sabrook 2
afsulator. The ERGS describe operator actives to respond to many of
'q the specific concerns expressed in the Sor H11e report.
Recweary actions are presented in two phasst.
In the first phase, e/
operator actions are directed toward equahrfog prIsery and affected steam generator pressure and terminating 51 to stop primary-to-secondary feakage. At the compietfon of this first phase, release $
from the affected steam generator wwld have stopped and all 4
fastediate safety concerns would be resolvt.d. D e second phase of the recovery cools and depressurf res both the RC5 and affeted stese generator to cold shutdown conditions.
Three siternative methods are described in the ERGS for completing t%f s phase. The cooldown to cold shutdown f s unaffected by ccinc1detit signal 11 actuatten logic or prior actuation of 51. Presevre in the affectse steam ger. orator would remain greater than that i. the intact steam generators since it would have been isolated. This is a necessary condition to maintain subcooling in the reactor coolant syn as, it is not clear with the infonsation prosected. Aether or not the recovery strategy proposed for lorselle etals mahtain the subceoling margin necessary to avoid $1 fattfatten.
Recent analysfs wort sponsorou by the WOE has feentIf fod criterf a by which operators can af Stings (sh between as %TR and a small4 reek LOCA, such that trPs will be kept running for an SGTR end manually trfpped for a LOC 4.
One report escribing these ana'yses has been trannaltted to the IRC and a second report afil he transattted within M days. Plant spectf fc procedures containing these criterf a for kooping RCPs in operation derIng an MTe will noen be in effect.
a J
F 9
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- p.
Pf;.f..
.c OG 114 dNf^.i 1
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jedi.
Mr. Darrell 8. Eisenhet
-4 Fdruary 17, 1984
/7.
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It f' our conclusion that there is no benefit to be gained by restoratica s
of the low pressertzer pressure - Tow pressurizer level cofncident sip 31 for initiation of safety injection in Westinghouse-suppifed
, 9.: -
' re:ctors in the U.S. We trust that this letter answers the specific
, '.'questfon asked in your 1stter of November 15 and provides suffic.ient
. background information to seable you to concur wf th our conc!vsIon.
Very truly yours.
~
' V,1.
J. J. Sheppard. Chatrnen Westinghouse owners e,p i
c cc NOG lteps Analysis 5/C C, '
~
. Procedures 5/C H. V..Julian l
.c 1-
- 5. Monty R. Sursen W'P
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