ML20112H077
| ML20112H077 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 03/27/1985 |
| From: | Carey J DUQUESNE LIGHT CO. |
| To: | Thompson H Office of Nuclear Reactor Regulation |
| References | |
| 2NRC-5-052, 2NRC-5-52, GL-84-08, GL-84-8, NUDOCS 8504020121 | |
| Download: ML20112H077 (5) | |
Text
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'Af di2Na'fs~t Nuclear Construction Division Telecopy 1 IttIEgb'is205 March 27, 1985 United States Nuclear Regulatory Comission f
Washington, DC 20555 ATTENTION: Mr. Hugh L. Thompson, Jr., Director Division of Licensing Office of Nuclear Reactor Regulation
SUBJECT:
Beaver Valley Power Station - Unit No. 2 Docket No. 50-412 GNLR 84-08 Appeal Meeting Request and Position Statement on the Issue of a Fourth Steam Generator Level Channel
REFERENCES:
(a) NRC letter dated January 10, 1985 from G. W. Knighton to E. J. Woolever (b) DLC letter 2NRC-4-068, dated May 30, 1984 Gentlemen:
This letter is in response to Reference (a).
In that letter, the NRC staff amplified on the backfit requiring that a fourth steam generator water level channel be added to the Beaver Valley Power Station Unit No. 2 protec-tion system for steam generator high water level. The previous staff position was provided in the Draft SER Section 7.3.3.12.
The Duquesne Light Company (DLC) response to the draft SER section was provided by Reference (b).
The NRC Licensing Project Manager in charge of backfits has verbally informed DLC that the first appeal of this issue is scheduled for 10:00 a.m.
on Ap.il 4, 1985.
The NRR procedure for management of plant specific backfitting speci-fies that the appeal meeting agenda developed from the staff 'and licensee positions be distributed prior to any meeting. An outline of DLC's positions on this issue is attached to facilitate the Project Manager's development of such.
Should the attached information be sufficient to close this issue, please notify DLC on such a decision preferably at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> before the scheduled appeal meeting.
DUQUESNE LIGHT OMPANY By J.p./,Cafey
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VicVPre'sident B504020121 850327 PDR ADOCK 05000412 A
PDR i
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- United States Nuclear R.gulatory Comissicn
.Mr. Hugh L. Thompson, Jr., Director
- buquesne Light Company Backfits Page 2 RWF/wjs Attachments cc: Mr. S. Chesnut, Technical Assistant (w/a)
.f Mr. M. Clausen, Technical Assistant (w/a)
- ld Mr. H. Denton, Director NRR (w/a)
Mr. V. Nerses, Project Manager (w/a)
Mr. T. Novak, Assistant Director (w/a)
Mr. B. K. Singh, Project Manager (w/a)
Mt. V. Stello, DEDROGR (w/a)
Mr. J. Tourtellotte, Chairman RRTF (w/a)
Mr. G. Walton, NRC Resident Inspector (w/a)
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ATTACHME;:7 2
. PACE 1 CF 1 ISSUE: Steats Cenerator L m l BACKFIT ISSUE No.:
L-84-13 TO DLC RESPONSE TO NRC 1.ETTER DATED 01/10/85 DLC BACKFIT NO.: _9 05/30/84 01/10/85 Backfit NH C Rqmn t s Appeal Pos it ion Meeting First Minutes &
Second MeetinR Sec ond Minutes &
Formal identified Letter Filed St at ement Agenda Appeal Decision Appeal Agenda Appeal Decision A ppeal Submitted issued Meeting Issued Requested issued Meeting Issued Req ue s t to Dir, NRR NRC POSITION DLC POSITION COMMENTS DLC has demonstrated that steam gener at or over-PROPOSED
'u caff schaeuledges that the stated serformaare requiressat can b+ set be REQUIREMENTS t*e addettaa et a fourth s.s. Tevel c*aaaet. The sta'f has. hisever. erovided fill prot ect ion.i s provided for Beaver Valley pai,sts to th. rsan. chaotw 15. does taha mdte fee the see verenecHe.t saf**y Power Scatson Unit 2.
See Attachment I for a se esportsatty 4r al waattve resafettoes of the issue. The e t
sesw.
'eetha of the H-ht 'm1 trip 4 themetysts ce feedma*w intes discussion on how plent protection is provided.
eat *v ttleas caustat sa tacrease to feedwever fiow. The staff has fadica**d a
that eparator acteaa can De credited.for lietallag feedmater flew te p'eveat steam grees'er averf t11 of the ressaase te such eveats at say pe=er level is not required to less than tea muutos or et steam generator eveeftil eveats can tie snown to have ao safety sigatf tcance. The asolicaat has not desanstrated
'het steam generator everf tll has ne safety stptficance in leaver Valley-2.
Although t aptitcaat assessed the eparator actten ttee dwetag sa increase in fe*dmater f ou event at fell pnmer, he has not provided se evaluetten of the opeester actten ttee far such aa event at low powerwhere the time available
=eute tie essected te be less, e
The staf f has not demo ns t ra t ed that application OW PROPOSED of 10CFR50.55( a)(h) is req uired to ach i eve an REQUIREMENT The safete concera to this usue is the averft111]' "of a steaa geaprater ud
- " con"s"ensa**ts", a'nd/or the ceaseque"nt p"te'attet'for es'es"sive"ly ca"te"co"t" tag accept able level of safet7 DI.C has demonstrated 8 ' ' ' '
WOULD the o
c s
e IMPROVE of the e,acter enetant system, a,setettee of the issue is espected to pentde that safety is not significantly impai red (see
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A t t achment 1) as per GDC 2ta, " Separation of SA FETY Protection and Cont rol Systems."
L RELATION OF Table 15.0-6 incorrectly lists the f eed wat e r A brief discussion will isolation on high st ems generator level as an be ad ded to FSAR Sect ion NEW REQUIRE-MENT TO Engineered Safeguards Feature (ESF).
DLC and 15.1.2 wh ich desc r ibe s EXISTING Westinghouse aRree that the high steam generator the January 16, 1985 I' vel Produced feedwater i so la t ion fo r Beaver event at Meaver Valley h"',M'M,'%e[t ea REGITLATORY e
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se POSITIONS (FsFt acevaHen functie, ed to F5aa sec. 7.3.2.2.4 that rhe destga of tsFa5 Valley tinit 2 is not an ESF system. Table 15.0-6 Un it I and the subsequent systers,is coaststent e.wtea. These statmats m mststet =sth the stare, correctly shows that no ESP equipme nt (last automatic protection th t!!! std. 279 1972 sect $oa 4.7 ta the seeticattea er the sia ie f atiire ect cettwta aselle ble to this tss.* as set forth ta sat sect.icas. 7,3. to Column) is ac t ua t ed.
The high level feed wa t.e r ac t ions that occurred.
71 and n e. e to see Sectten F.1.
The
- svee volte, 2 three isolat son signal is used as a convenient to y a nt This viiI ad d r e s s how re
- e. ace. Tatt e
o ca e,i s.s. te el contrei/sretecteoa srst.aa does act me tw 5'e aw aan it terminate P. h e analysis of the ex ces s fe edwat e r both the React or Prot ec-a,,.e to acet.he et.et tceat's statea.at. rsae s c. 7.3.2'.t.4 event in Sect ion 15.1.2 of the FSAR. Table 15.0-6 tion System and Engi-
'hte sooitentie to the sta" is msisteat =+t* the practts.s ** t** S'e ed ste** positieas p.vta.siv om ed.
N
- %<*. this is e em'9* 4 v.
will be revised to correct this inconsistency by neered SafeRards Features ante c514 r** Seets cat placing "4A" under the coluen entitled ESF Actua-Systems were initisted.
tion Functions.
The SRP criteria applicable to this signal should be SRP Sect ion 7.7 e rather than the criteria in SRP Se c t ion 7.3.
Therefore, FSAR Section 7.3.2.2.4 is not applicable.
SUCCESTED No comment.
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ATTACHMENT 1 Demonstration of Plant Protection
REFERENCE:
2NRC-4-076, dated June 8,1984 JUSTIFICATION:
In the above reference, DLC demonstrated that there would be adequate time during an increase in feedwater flow at full power (assuming no protection systems response) for the oper-ator to prevent steam generator overfill. It was demonstrated that the operator could quickly defeat the automatic feed-water control system and manually bring the steam generator water level back to normal operating levels.
A recent event at Beaver Valley 1 (BV-1) has indicated that the focus of previous evalutions (by both DLC and the staff) has been too narrowly defined. Due to the highly integrated nature of the plant design, a rapid increase in feedwater flow affects a number of significant parameters in addition to feedwater merely filling the steam generator volume.
Although DLC still contends that the operator actions needed to respond to a feedwater control system malfunction are easily identifled and accomplished for any excess feedwater event, automatic protective action would correct the situa-tion more quickly than the operator could respond for a large excess feedwater event. On January 16,1985, BV-1 experienced an inverter failure while operating near 100% power.
One complication of this failure was that the steam generator water level controlling channel fell to zero.
This immedi-ately caused the automatic feedwater level control system to increase the feedwater flow at the maximum possible rate.
Although this failure produced many annunciated alarms, the control room operators assessed the situation and, in a matter of a few seconds, accurately concluded that the increased feedwater flow was the condition most demanding immediate attention.
(Operators relate that their training and experience cause them to be highly sensitive to feedwater responses during plant transients).
Within approximately 20 seconds, the feedwater flow increase was halted on all three steam generators by taking the feed-water control systems out of automatic.
The operator then started manually reducing "B" steam generator feedwater flow rate. Flow had been dropped to well below the pre-event flow rate by about 60 seconds.
"C" steam generator feedwater flow reduction began at about 50 seconds and flow was decreased below the pre-event flow at about 70 seconds.
The operator had started reducing the feedwater flow on "A" steam genera-tor at about 80 seconds, but, despite the prompt and appro-priate operator response, the plant tripped (at 103 seconds) before the operator could complete his actions to reduce feedwater fl ow.
The plant tripped on low steam generator pressure due to its rapid rate of decrease concurrent with Safety Injection, Main Steam Isolation, and Feedwater Isola-tion.
The available data indicates that all three steam generator pressures were reacting uniformly to the transient.
Thus, no one steam generator reduced its steaming rate enough to cause the steam line check valve to close.
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" In i.he last refueling, DLC had installed a new computer r
system to monitor and record major plant parameters both before and following any plant trip on Beaver Valley Unit 1.
Reviewing this data for the event, the total feedwater flow had increased and stopped at approximately 115% flow in 15-20 seconds followed by a sequential reduction of flow to the stean generators.
Even though feedwater flow was being rapidly reduced, the plant still tripped in less than 2 minutes.
The plant would have tripped even more quickly if no operator action had been taken.
Thus, it has been demon-strated through an actual plant transient that the Reactor Protection System (RPS) and Engineered Safeguards Features (ESF) Systems would intervene and provide protection for a large excess feedwater event.
t It should be noted that Beaver Valley Unit 1 and Unit 2 are effectively identical for the purposes of discussing the effects of an excess feedwater event.
Both plants have similar reactors, reactor coolant systems, steam generators, and feedwater systems.
Beaver Valley Unit 2 RPS and ESF setpoints are set at the same or more conservative values as Beaver Valley Unit 1.
DLC has subsequently evaluated the event, the data, and the systems involved and conludes that the 100% power event is the limiting case for one or more feedwater regulating valves failing open.
At full power the feedwater regulating valve 6
is at its farthest normal open position. Thus the increase of feedwater due to a feedwater regulating valve inadvertently going full open is the smallest.
At 20% power (the lowest power where the feedwater control is nonna11y placed into automatic) it is estimated ' that total feedwater would increase by about 30-35% of design full flow with 6 feedwater regulating valve full open, which is well above the 15% total flow increase experienced at full power at Beaver Valley Unit 1.
In addition, the feedwater temperature is 388'F at 20%
power rather than 443*F at full power, which increases the cooling capacity of any increased feedwater flow rate. Based on the above facts and the inherent systems relationships, the pressure drop and the rate of pressure drop of steam generator pressure for a full open feedwater regulating valve at 20% power will be at least equal to (or much greater than) that experienced by Beaver Valley Unit 1 on January 16, 1985, and also result in a reactor trip.
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DLC concludes that sufficient time is provided for operator intervention for the maximum full-power excess feedwater transient (and all other smaller excess feedwater events) as demonstrated by the referenced analysis. Adequate protection is also provided by the RPS and ESF systems and Beaver Valley Unit 2 for any excess feedwater flowrate equal to or greater than the above case as demonstrated by the January 16, 1985, full power transient on Beaver Valley Unit 1.
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