ML19327B902
| ML19327B902 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 11/03/1989 |
| From: | Pleniewicz R, Stauffer G COMMONWEALTH EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| BYRON-89-1067, LER-89-009-07, NUDOCS 8911140161 | |
| Download: ML19327B902 (10) | |
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CommonweaHh Edison e .e i ByronNuct'arStation 1
, l ' 4450 North G;rrren Church Road I
\ 7 Byron,lilinois 61010 i ,.
L November 3, 1989 Ltre BYRON 89-1067 i U. S. Nuclear Regulatory Commission Document Control Desk Washington, D.C. 20555
Dear Sir:
The enclosed Licensee Event Report from Byron Generating Station is being transmitted to you in accordance with the requirements of 10CTR50.73(a)(2)(v).
This report is number 89-009-00; Docket No. 50-454.
. Sincerely, R. Pleniewics Station Manager j Byron Nuclear Power Station 1'
RP/bb (0459R/0059R)
Enclosures Licensee Event Report No. 89-009-00 l
l cci A. Bert Davis, NRC Region III Administrator
- 1. W. Kropp, NRC Senior Resident Inspector INPO Record Center CECO Distribution List l
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l 8911140161 891100 PDR MA D
S ADOCK 05000454 ' l PNU
LICENSEE EVENT REPORT (LER) facility Name (1) ' Docket Number (2) '3ge (3)
B ron. Unit 1 015l01Qj014lSl_H 1!of!0lQ_
T{tle (4) INADLQUATE INCORPORATION OF STEAM GENERATOR BLOWDOWN ISOLATION REQUIREMENTS AS ASSUMED IN CERTAIN ACCIDENT ANALY",lS CAUSED BY A PRESERVICE DESIGN IMPLEMENTATION DEFICIENCY Event Date (5) LER Number (6) _ RepEtJate (7) Othen.[31111 tit 1_lnEnlYtd (8)
Year Year Sequential /j/j/ Revision Month Day Year Facility Names Docket Number (s)
Month Day //
fj/j/
// Number /j// Number BYRON UNIT 2 015101010141515
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11 0 01 5 81 9 Bl 9 0l0l9 01 0 1l1 01 3 Bl 9 01 El 010101 l L TH15 REPORT IS SUBMITTED PUR$l%NT TO THE f.EQUIREMENTS OF 10CFR OPERAi!NG (Check one or more of the followino) (11)
M00C (9) 1 20.402(b) _ 20.405(c) _ 50.73(a)(2)(lv) _ 73.71(b)
POWER _ 20.405(s.)(1)(i) _ 50.36(c)(1) _E. 50.73(a)(2)(v) __ 73.71(c)
LEVEL _ 20.405(a)(1)(ll) ._._ 50.36(c)(2) ._ 50.73(a)(2)(vil) _ Other (Specify (10) 1 !0l 1._. _ 20.405(a)(1)(lii) _ 50.73(a)(2)(1) _ 50.73(a)(2)(vill)(A) in Abstract
////////////,/////////////,/ _ 20.a05(a)(1)(iv) _ 50.73(a)(2)(li) _ 50.73(a)(2)(stil)(B) below and in
///////////}////////////'j/
/ / _ 20.405(a)(1)(v) _ 50.73(a)(2)(iii) _ _ 50.73(a)(2)(x) Text)
LICENSEE CONTACT FOR THIS LER (121 _,
Name TELFJfjQgE NUPSER AREA CODE Garv Stauf fer. Assistant Technical Staf f Supervisor Ext. 2274 8l 1!5 2 13 14 l -l 51 41 41 CONPLETE ONE LINE FOR EACH CONPONEN FAILURE DESCRIBED IN THIS REPORT (13)
CAUSE SYSTEM COMPONENT MANUFAC- REPORTABLE CAUSE SYSTEM COMPONENT MANUFAC- REPORTABLE TURER TO NPROS TURER T0 NPRDS I _[ l l I I I I I I l _.} _ l l 1 I I I I I I I I I I I I I TUPPLEDENTAL REPORT EXPECTED (14) Expected Nonth l Day l Year Submission lyes (If vafdompleit_ EXPECTED._SUBM15$10N DATE) X l NO
" l l1 lI ABSTRACT (t% t to 1400 spaces, i.e, approximately fif teen single-space typewritten lines) (16)
During view of erosion / corrosion concerns for the Steam Generator blowdown (SD) lines, conflicting Informa . e aegarding signals that initiate automatic isolation of the SD lines was discovered by Byron site put .. r el . The SD isolation was confirmed to occur on a Containment Phase A signal (generated on receipt of any Safety injection Signal (SIS)) and an Auxiliary Building high temperature signal (high energy line break consideration). Huwever, the Updated Final Safety Analysis Report (UFSAR) indicated that automatic SD isolation would also occur on other signals.
Discussions with Westinghouse indicated that SD isolation on a $15 and 2 of 4 Steam Generator (SG) level low-low signal were assumed in certain accident analyses. The effect of not isolating SD when required is to reduce the Auxiliary Feedwater (AF) flow provided to the SG for cooling.
As interim corrective action SD was isolated at 12:00 on 10/05/89 until temporary procedure changes were implemented that required manual isolation of blowdown whenever a reactor trip occurs to replicate the UFSAR accident analysis.
An engineering evaluation was provided to the station on 10/25/89 which demonstrated that the assumptions of the accident analyses have satisfactorily been met for past and interim operations in conjunction with the revised operating procedures until a permanent modification can be implemented.
The proximate cause of the event was a preservice design implementation deficiency. The SD system functional requirements identified several signals to provide SD isolation. however isolation on SG 1evel low-low was not physically Incorporated for unknown reasons.
This ever.. is reportable per 10CFR50.73(a)(2)(v). There have beer, no previous similar events.
(0459R/0059R)
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- j LICf,M$EE EVENT REPORT fLER) TEXT CONTINUATION rarm Rev 2.0 FACILITY N#iE (1) DOCKET NUPSER (2) LER NUIRER f6) Pane (31 Year /// Sequential fff /jj f
// Revision di _Nygher /// Number avron. Unit 1 015101010 l 41514 819 - 010l9 - 0 l0 0 12 0F 0 L9 :
TEXT . Energy Industry Identification System (E!!S) codes are identified in the text as (XX) l1 A. PLANT CO ITIONS PRIOR 70 EVENT:
Eveat Date/ Time- 10/05/89 / 1200 Unit i MDDE - 1 - Power Goeration Rx Power .100% RCS (AB) Tesiperature/ Pressure Normal Doerating.
Unit 2 MDDE 1 - Power Operation- Rx Power _,_95. RCS (AB) Temperaturv/ Pressure JinI m 1 Doeratina
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l B. DESCRIPTION OF EVENT:
During a review of erosion / corrosion concerns for the Steam Generator blowdown (SD)(WI) lines, conflicting '
Information regarding signals that initiate automatic isolation of the SD lines was discovered by Byron l 'ite personnel. Ur$AR Figure 7.2-1 sheet 15 of 18 (Westinghouse drawing 1080685) indicates the 50 and
! sample line valves (1/2SD002A through H and 1/2SD005A through D respectively) close on the following i signals: (1) local manual start of the Aux 111ery Feedwater (AF) (BA) Pumps (2) Control Room Manual start
- of the AF Pumps (3) Safety Injection Signal (SIS) (4) Loss of Power signal (2 of 4 Reactor Coolant Pump bus l undervoltage) and (5) 2 of 4 Steam Generator (SG) (A8) level low-low. However, the UFSAR text does not I discuss all of these isolation signals. Section 9.3.2.2.2 indicates Steam Generator blowdown process and i sample containment isolation valves are automatically closed on high containment pressure (containment '
pressure high-1 would generate a SIS). Section 10.4.8 states blowdown lines from each steam generator have two air operated valves capable of auto closure. Also Table 15.1-2 identifies equipment required following i a rupture of a main steam line which includes the SD isolation valves auto closure feature. Review of the Byron Station schematic dingtems for the SD isolation and sample valves was completed and indicated isolation is only provided by (1) Containment Phase A isolation signal (Phase A is generated by any SIS) and (2) Auxillary Building high temperature (High Energy Line Break (HELB) consideration).
On 10/02/89 this discrepancy was discussed with Westinghouse. Westinghouse indicated that SD and sample valve isolation on only a S!$ and 2 of 4 steam generator level low-low signal were assumed in certain accident analyses. The AF system provides water to the Steam Generators to remove residual and decay heat from the Reactor Coolant System (RCS). The ef fect of not isolating the SD and sample lines is to reduce the net amount of AF water delivered to the SG. For those accident scenarios relying en AF, this can impact the Departure from Nucleate Boiling Ratio (DNBR) and result in system overpressurization.
Westinghouse also identified a series of letters written in 1980 regarding the potential for reduced secor4ary cooling with SD isolation valve failures. The Westinghouse to Ceco letters dated 02/20/80, 04/11/80 and 05/09/80 were retrieved from Westinghouse flies on 10/03/89. The letters recommended that the design of the AF and SD Systems be evaluated to ensure that the not flow to the intact steam generators is not less than the AF requirements as stated in the SAR analysis. The letters also stated that if the analysis performed showed that the licensing basis was marginally met or not met, consideration should be given to making plant modifications such as adding an additional SD isolation valve or adding HELt l
restraints. A Sargent & Lurdy to CECO letter dated 05/14/80 addressed this issue and determined that no new valves or restraints were required. These Westinghouse letters did not specifically discuss SD isolation on a SG 1evel low-low signal and the Sargent & Lundy letter did not identify any concerns with not having SD isolation on SG 1evel low-low.
(0459R/0059R)
1 j L KENSER [ VENT REPORT (LER) TEXT EQtfHt@MION Form Rev 2.0 FACILITY NAME (1) DOCKET NUPSER (2) ,_LLlLifut9EILH.i ... Pagt E l Year /// Sequential /// Revision
/p/j/f . Nyghgr_,__ /j/j f
/ _ Number _
.lzIDL_ Unit 1 01510101014LSI 4 819 .- 01019 - O l0 Q_j3 0F 019 TEXT Energy Industry Identification System (E!!$) codes are identified in the text as (XX)
The preliminary station and engineering review completed on 10/05/89 could not conclude that AF actuation without SD isolation had been adequately resolved in the past. Therefore as a conservative action, valves 1/2SD002A through H and sample valves 1/2SD005A through D were closed at 12:00 on 10/05/89, thereby securing SG blowdown on both units. The appropriate NRC notification via the [HS phone system was made at 1253 pursuant to 10CFR50.72(b)(2)(iii). Plant operation with the SD valves isolated could not continue fer any extended period of time without adverse consequences on the SG secondary cheelstry which would ultimately require a unit shutdown. Temporary procedure changes were implemented for 1/2BEP O (Reactor Trip or Safety Injection),1/2 BCA 0.0 (Loss of all AC Power),1/2BFR 5.1 (Response to Nuclear Power Generation /ATWS) and 1/2 BFR H.1 (Response to Loss of Secondary Heat $1nk), requiring operators to close the steam generator blowdown and sample isolation valves on any reacter trip signal. Procedures 1/2BfR H.5 (Response to Steam Generator Low Level) already had contained a step requiring SD isolation. Since the temporary procedure changes replicated the assumptinns in the iccident analysis, On-site Review 89-227 dated 10/05/89 concluded that it was acceptable to re-establish SG blowdown untti CICo engineering and Westinghouse could conduct a more detailed review of plant construction docementation and of additional accident analyses to verify that AF actuation without SD isolation had already been analyzed or considered if required. A daily order was issued to operations personnel on 10/05/89 notifying the operators of the temporary procedure changes and training was also conducted for shif t personnel.
On 10/25/89 the Station received the engineering evaluation of AF actuation without automatic SD isolation performed by CECO Engineering and Westinghouse. The evaluation concluded thet even though the accident analyses assumed SD isolation on a SG 1evel low-low signal, the AF system would still be capable of performing its intended function to mitigate the consequences of the affected LOCA and non-LOCA transients. It also concluded that interim operation was acceptable with the temporary procedure revisions currently existing based on the reanalysis donc until a permanent sradification design and implementation could be completed. An On-Site Review 89-245 was performed which accepted the results of this engineering evaluation.
There were no systems or components inoperable at the beginning of the event that contributed to the event. Operator actione did not impact this event. The event is reportable per 10CFR50.73(a)(2)(v).
C. CAVSE OF EVENTt The proximate cause of the event was a preservice design implementation deficiency. The 50 system functional requirements identified several signals to provide SD isolation, however isolation on SG 1evel low-low was not physically incorporated.
P (04591/0059R)
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.LICEt($EE_[YENT REPORT _ILER) TEXT CONTINuAUON Forg Rev 2.0 FACILITY NAME (1) D0CKET NUMBER (2) __LLlL!NtBER (6) Pane (31 .
Year j///ff Sequential /j/j/ Revision ,
f
/// Number /// Number i L _tyron. Uni _t 1 0 l 5 l 0 1 0 1 0 l Alga 819 - 010l9 - 0 10 0 14 0F 0l9 TEXT Energy Industry identification System (E!!$) codes are identified in the text as (XX)
The SD System functional requirements identified other isolation signals in addition to the SIS and $G 1evel low-low signals that Westinghouse currently states are the $0 isolation signals assumed in the accident analysts. The Steam systems Destpn Manual SG-689 issued in 19T9 indicates the blowdown and sample containment isolation valves must be designed to close automatically when AF receives an automatic ,
actuation signal. There are several AF actuation signals that do not provide $D isolation (2 of 4 RCP bus undervoltage and E$F bus undervoltage). UFSAR Figure 7.2-1 sheet 15 of 18 (prepared from Westinghouse logic drawing 108D685) indicates that Westinghouse provided the required blowdown and sample line valve ,
isolation signals, but other vendors provided the physical wiring to install the isolation signal. Again this figure has several signals that in fact do not provide $D isolation, including manual start of the AF pumps. The serivs of letters issued in 1980 regarding the potential for reduced secondary cooling with $D isolation valve f ailures did not specifically address 50 isolation on $G 1evel low-low and the design concern was not recognized at this time.
The SD isolation valves, 1/2$DD02A through H and 1/2$D005A through 0, are included in Technical Specification 3/4.6.3 for containment isolation valves. The AF system is discussed in Technical Specifications 3/4.3.2 and 3/4.7.1.2 and the $D isolation valves are not addressed in these specifications. Therefore the impact on AF operability from the lack of SD isolation on a $G 1evel low-low signal would not be apparent from the Technical Specifications.
$1nce the original design discussions occurred approximately 10 years ago, it is difficult to determine the root cause of the preservice design implementation deficiency. As poted, there are several SD isolation signals discussed as part of the original design that were not incorporated into the final plant construction and are determined not to be required since they are not assumptions in the accident analyses. The SG 1evel low-low SD isolation signal may have been addressed in the original design, but there is insufficient documentation to arrive at this conclusion. No further investigations are planned.
D. SAFETY. ANALYSIS:
The design function of the AF system is to provide adequate cooling water to the steam generators to remove residual and decay heat from the RCS when the normal feedwater system is unavailable. The AF system allows the RCF to be cooled to a temperature where the residual heat removal system can be placed in operation.
The ef fect of not isolating the steam generator blowdown and sample lines is to reduce the net amount of AF water delivered to the $Gs. For those accident scenarios relying on AF, failure to isolate SD and the sample valves can impact the DNBR and system overpressurization. The following is a discussion of the effects on the non-LOCA and LOCA accident analysis.
HQ_N-LOCA IMPACT - The impact of not automatically isolating the steam generator blowdown and sample lines af fects those transients in which auxillary feedwater (AF) is relied upon to remove long term core decay heat. These events include the Loss of Normal Feedwater event (UFSAR 15.2.7), the loss of Non emergency AC Power to the Plant Auxillaries (UFSAR 15.2.6), and the Feedwater System Pipe Break (UFSAR 15.2.8). The l remaining Chapter 15 events are not Impacted by a reduction in AF delivery. In order to quantify the l: ef fects of the reduction in AF flow for the af fected accidents, the cases presented in the UFSAR were reanalyzed as follows.
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- m. LICENSEE EVENT REPORT (LER) TEXT CONTINUAfl0N form Rev 2.0 DOCKET NUPSER (2) LER NUfeEk (6) pane (3)
FACILITY NANE (1) ..
Year Sequential y Revision l-Number U1 _Hyghir_
,Jyron. Unit 1 ,Ql5101010ljj 4 8l9 - Ol019 - 0 l0 0_l5 0F 0l9 lEXT Energy Industry Identification System (E!!$) codes tire identified in the text as (XX)
LOSS OF NDRMAL FEEDWATER/LO)LQLj@tl-EMERGENCY AC UNClt . The loss of Normal Feedwater/ Loss of AC power events are ANS Condition II transients. Thus, the acceptance criteria are based on DNBR and system l overpressurization. In addition, the plant must be capable of returning to operation after corrective l action and the event can not generate a more severe transient. $1nce these events are bounded by other transients with respect to potential fuel damage, DNBR is not a concern. The Westinghouse acceptance criterion, therefore, is based on not pertitting the pressurizer to go water solid. This ensures that the RCS doas not overpressurize and that primary ef fluent does not spill to containment.
In order to generate margin to offset the AF penalty of not immediately isolating SD, better-estimate analyses were performed to justify previous operation. The assumptions that went into these analyses are detailed below. Note that the single f ailure assumption of one of the two AF pumps f alling to start was not changed. If the single failure assumption is removed, then the flow provided by the second pump more than offsets that lost via the blowdown lines and new analyses would not bs required.
- a. The initial power level was based on 100% of the currently licensed NS$$ rating (3425 MWt) instead of the UFSAR assumption of 102% of the ESF rating (3579 MWt). This is a reduction of 225 MWt and Is based on actual plant operating conditions.
- b. The remainder of the uncertaintles on initial conditions were removed. Noelnr.1 values for RCS temperature, feedwater temperature, and pressurizer pressure were used.
- c. A nominal value of 14 MWt for reactor coolant pump (RCP) heat was used rather than a maximum value of 20 MWt.
- d. The actual plant value of 27 ft3 for the AF piping purge volume was assumed instead of the conservative UFSAR value of 50 ft3 .
- e. The 50 lines were assumed to remove 90 gpm per steam generator. This value bounds all four Byron and Braidwood units.
- f. The operators were assumed to manually isolate the blowdown lines from the control room at 10 minutes.
- g. Based on actual AF performance calculations,160 gpm was assumed to be delivered to each steam generator once the isolation valves are closed. This corresponds to 640 gpm supplied to all 4 steam generators. Prior to isolation, 70 gpm was assumed to be delivered to each steam generator.
- h. Core residual heat generation was based on the 1979 version of ANS 5.1 including a 2-sigma uncertainty. ANSI /ANS-5.1-1979 is a conservative representation of the decay energy release rates.
(0459R/0059R)
I LIEENSEE EVENT REPORT _(LER) TEXLCQ!{UNUATION Fgru Rev 2.0 FACILITY NAME (1) DOCKET NUteER (2) _LE!L!fut$fR (6) PggtSI Year // Sequential // Revision
//j/j/
f Number /j//j/j Number I tyron. Unit 1 015101 O l 0141514 8l9 - 0I019 - 0 j0 0 16 0F 0l9 TEXT Energy Industry Idertification System (Ell $) codes are identified in the text as (XX)
Two sets of analyses were performed to encompass all four units (B/ ron and Braidwood Units I and 2). One ,
analysis assumed nominal conditions based on an RCS average temperature of 588.4'F. The other analysis was j based on an ACS average temperature of 569.I'F. The two analyses were necessary because several of the units operate under the That Reduction Program but Braidwood Unit 2 does not. This program is detciled in WCAP-11386.
The results of these analyses demonstrated that all the UFSAR acceptance criteria would still be satisfied given the assumptions identified above. The nominal temperature cases resulted in peak pressurizer water volumes of 1548 ft3 and 1549 ft3 for the Loss of Normal Feedwater and Loss of AC Power events, respectively. For the reduced temperature cases, the peak pressuriser water volumes were 1504 ft3 and ;
1619 ft 3, respectively. The pressurizer PORVs and main steam safety valves (MSSVs) limit peak primary {'
and secondary pressures to less than 110% of design. The pressuriser safety valves would have prevented overpressurization had'the PORVs been unavailable.
Therefore, based on these better-estimate analyses, the UFSAR criteria were satisfied and, subsequently, j the conclusions presented in the UFSAR remain valid for past operation. i FEEDWATER SYSTEM PIPE BREAK - ine Feedline Break event also relies on the delivery of AF to remove residual ,
and decay heat from the RCS. In order to quantify the effects of the reduction in AF on this event, the )
two UFSAR cases (both with and without offsite power available) were reanalyzed.
I The feedline Break event is an ANS Condition IV transient. The applicable acceptance criterion is to j demonstrate that the core remains intact and in a coolable geometry. The more restrictive Westinghouse criterion is to show that the kCS remains subcooled, thus ensuring that bulk bolling in the hot legs does not occur.
Consistent with the analyses discussed above, better-estimate assumptions were used in this analysis to justify previous operation. Again, if the single failure assumption is removed, then the flow provided by ;
the second pump more than offsets that lost via the blowdown lines and a new analyses would not be required. I
- a. The initial power level was based on 100% of the ESF rating (3579 MWt) instead of 102%. This is a reduction of 72 MWt and reflects nominal uprated plant performance,
- b. The remainder of the uncertainties on initial conditions were removed. Nominal values for RCS l temperature, feedwater temperature, and pressurlaer pressure were used.
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- c. A nominal value of 14 MWt for react sr coolant pump (RCP) heat was used rather than a maximum value of 20 MWt.
- d. The actual plant value of 27 ft3 for the AF piping purge volume was assumed instead of the l conservative UFSAR value of 50 ft3.
- e. The SD lines were assumed to remove 90 gpm per steam generator. This vc';e bounds all four Byron l and Braidwood units.
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LICEN$LLEYINIJttPORT f LER) TEXT CQHIl}R Q10N Form Rev 2.0 l FACILITY NAME (1) DOCKET NVPSER (2) LER NUPBER (6) Pane (3) I Year / Sequential / Revision *
/j/j/j/
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// Number _
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,)yron. Unit 1 0 l 5 1 0 1 0 1 0 1 41 51 4 819 - 01019 _ . . O l0 0 17 0F 0 l_,9 TEXT Energy Industry Identification $ystem (E!!$) codes are identified in the text as [XX)
- f. The blowdown lines were assumed to be la.olated by a $1$ generated by the Low $teamline Pressure function and is supported by existing plant logic (containment phase "a" Isolation on any $1$
signal). This signal is actuated about 6 minutes into the transient,
- g. Based on actual AF performance calculations provided by the utility, 160 gpm was assumed to be delivered to each steam generator once the isolation valves are closed. This corresponds to 480 gpm supplied to the 3 intact steam generators. Prior to isolation, 70 gpm was assumed to be delivered to each steam generator,
- h. Core residual heat generation was based on the 1979 version of ANS 5.1 including a 2 sigma uncertainty. AN$1/ANS-5.1-1979 is a conservative representation of the decay energy release rates.
Only one analysis was perfomed for Feedline Break to address all four units because WCAP-11386 concluded ;
that nominal temperature conditions (i.e.. based on a RCS average temperature of 588.4'F) are limiting.
The results of this analysis demonstrated that the UFSAR acceptance criterion would still be satisfied given the assumptions identified above.
The results showed that the minimum subcooling margin for both the with and without offsite power cases was 33*F. The pressurizer safety valves and MSSVs limit peak primary and secondary pressures to less than 110%
of design. Therefore, based on this better-estimate analysis, the UFSAR criteria is satisfied and, subsequently, the conclusions presented in the UFSAR remain valid for previous operation.
1114MLINE BREAK MASS & ENERGY RELEASES - The reduction in AF has the potential to impact the Steamline Break Mass & Energy Releases calculated both inside containment for containment integrity (UFSAR 6.2.1.4) and outside containment for equipment qualification (WCAP-10961-P).
For the mass and energy releases inside containment, primary protection is provided by either a Containment Pressure High-1 or a low $teamline Pressure signal. Both of these functions generate a $l$ as well as reactor trip and AF actuation. Thus, the SD isolation valves will be closed and no AF will be lost.
Therefore, this scenario does not impact the mass and energy releasas inside containment.
For the mass and energy releases outside containment, the program detailed in WCAP-10961-p was developed to identify what equipment modifications, on a forward fit basis, were necessary to ensure proper operation of safety-related equipment in the auxiliary buildings. Since these equipment modifications only address future operation, it is inappropriate to consider this scenario against the generation of the mass and energy releases for past operation. The auxiliary feedwater performance currently assumed in this program for Byron /Braldwood will be preserved for both interim and permanent operation in the future.
LQCA IMPACI - The calculated consequences for both the large and small break LOCA analyses appearing in the UFSAR assume isolation of the SD lines. This isolation will occur on a SIS as a result of pressurizer low pressure. $1nce the isolation function is provided for a SIS the UFSAR large and small break LOCA analyses are not affected. Tutther, the Thot reduction analyses (WCAP-ll387 Rev.1) and the VANTAGE 5 fuel analyses are not affected.
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LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Form key 2.0 FACit1TY NAME (1) DOCKET NUNCR (2) _LER NUSER (6) pane (3)
Year /// Sequential / Revision
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Number j///g/
/ Number _
Bvron. Unit I 0 l 5 1 0 1 0 l 0 l 41 S QL J LL -
o I oJ 9 - o Io o is or ols TEXT Energy Industry Identification System (Ell 5) codes are identified in the text as (XX) in addition, the LOCA analyses or licensing positions that are not affected by assumptions for Steam '
Generator Blowdown line isolation include 1) LOCA hydraulle forcing function analyses used to develop LOCA loads on the reactor internals and RCS loop piping, 2) Post-LOCA boron concentration required to keep the
. reactor soberitical and 3) Switchover of the ECCS to hot leg recirculation required to prevent the potential for boron precipitation.
CONCLUSION - The ef fects of the scenarios identified above, involving the lack of automatic isolation of the steam generator blowdown and sample lines on an $G 1evel low-low signal (AF actuation signal), have been evaluated against the non-t0CA and LOCA accident analyses. This evaluation has concluded that while the plants did not have SD isolation on SG 1evel low-low assumed in the accident analyses, at no time were the plants in a condition that posed significant risk to public health and safety. These better-estimate loss of Normal Feedwater, Loss of AC Power, and Feedline Break analyses conclude that with the assumptions itemixed above, the UFSAR acceptance criteria are satisfied and the conclusions of the UFSAR are still valid. All other UFSAR Chapter 15 transients are unaf fected by this potential scenario.
The better-estimate assumptions used in the above analyses are permissible in addressing previous operation, and for future operation provided that operator action to isolate the SG blowdown lines is accomplished in 10 minutes following a reactor trip and this requirement is included in the plant operating i procedures. Prior to the temporary procedure changes, the requirement to isolate SD did exist in the functional rostoration procedure 1/2BFR H.S (Loss of Heat Sink). In addition many station emergency procedures require vsrlfication that the steam generator level is greater than 4% of narrow range. If not, the operator is instructed to maintain AF flow greater than 500 gpm until narrow range level is greater than 4% in at least one steam generator. This allows the operator to evaluate the situation and increase l AF flow to greater than 500 gpm if level is not being restored. It is reasonable to assume the operator l
would also have recognized the need to isolate SD If there was any difficulty in restoring SG 1evel. Under I the worst case condition of sustained inadequate AF flow, the emergency procedures provide for e!ther the l estabitshment of feed to the SGs from the normal feedwater system or cooldown and depressurization of the l RCS to a point where the Residual Heat Removal System can be placed in service using redundant ECCS components.
l It is worthwhile to reiterate that had the limiting single failure assumption of one AF pump been removed, no analyses would have been required since a second pump more than makes up for the lost AF flow. In addition, a feedwater system pipe break that assumes SD lsolation on $G 1evel low-low has never occurred at Byron Station. However, there have been Loss of Normal feedwater and Loss of Non-Emergency AC Power events
, but review of Station documentation regarding these events indicates no adverse impact has occurred because of lack of SD isolation on SG 1evel low-low. The Byron and Braidwood stations are justified to continue to l
operate, based on the discussions presented above in conjunction with the revised operating procedures indicating a manual isolation of the SG blowdown and sample lines on any reactor trip signal. Closing the l SD and sample isolation valves on any reactor trip signal is more conservative than the assumptions in the t
accident analysis which assume isolation only on a $15 or Steam Generator level low-low signal. Also, a l permanent modification will be completed on a prudent schedule during the next outage of sufficient l
duration allowing for enginesring design, material procurement and outage scheduling.
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- ' LIGN$EE EVENT REPORT (Rl() TEXT CQMUNUATION Form Rev 2.0 l FACILITY NAME (1) DOCKET NUMBER (2) _.1LR_NyteER (6) Pagt Q)_ ___ i Year /// Sequential /j/j/j Revision fj/j
// __ Number
__ ML __ Number _
.jyron. Unit 1 . o l 5 1 2_Lo_.LQ_laL51.A _d 9 o!oI9 o Io QJ9 or d _9 TEXT Energy Industry Identification System (Ells) codes are identified in the text as (XX) '
E. CQRRECTIVE ACTIQHit When the preliminary review could not conclude that AF actuation without automatic SD isolation on SG 1evel level low-low was an acceptable design, the SG blowdown valves 1/2SD002A through H and the sample isolation valves 1/2 SD00$A through D were closed. Temporary procedure changas were implemented for 1/2 PEP 0, 1/2 BCA 0.0,1/2 BFR S.1 and 1/2 BFR H.1 requiring operators to close the steam generator blowdown and sample isolation valves on any reactor trip signal. These procedure changes replicated the assumptions in the accident analysis for dutomatic SD isolation on SG level low-low and Station On-Site Review (OSR 89-227 dated 10/05/89) determined it was acceptable to re-estabitsh SG blowdown untti CECO engineering and Westinghouse conducted a more detailed review of plant construction documentation and of additional accident analyses to verify that AF actuation without SD isolation had already been analyzed or considered if required.
On 10/25/89, the Station received the engineering evaluation of AF actuation without automatic SD isolation
- performed by CECO Engineering and Westinghouse. A station On-site Review (OSR 89-245 dated 10/31/89) deterwined that interim operation was acceptable with the temporary procedure revisions currently existing, based on the reanalysis performed, until a permanent modification can be implemented. The permanent modification will be completed on a prudent schedule during the next outage of suf ficient duration allowing '
for engineering design, material procurement and outage scheduling. The tentative schedule for Byron Unit I is the fourth refueling outage anticipated to consnence 09/17/91 and the second refueling outage for Byron Unit 2 anticipated to comunence 09/09/90. Action Item kecords (AIR) 454-225-89-29200 and 455-225-89-29300 will track the design development and installation of the modification. UFSAR Figure 7.2-1 will be revised to reflect only the signals required to provide SD isolation. These AIRS will also track any permanent procedure and other document changes required.
F. PREVIOUS OCCURRENCES:
A historical review of Byron's LERs has identified no known previous stellar events.
G. COMPONENT FAILURE DATA:
Not applicable.
(0459R/0059R)