ML20134D497

Forwards Rev 1 to Safety Evaluation Secl 90-469.Revised Safety Evaluation Clarifies Section of ASME Code Associated W/Main Steam Safety Valves in Reference to 901031 Ltr CAE-90-315/CCE-90-310

ML20134D497
Person / Time
Site:	Byron, Braidwood
Issue date:	07/22/1991
From:	Humphries B WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:	Pleniewicz R COMMONWEALTH EDISON CO.
References
NUDOCS 9610220382
Download: ML20134D497 (150)

Text

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ma Westinghouse Energy Systems suc,,,, no e ,nc,c N'

Electric Corporation tecnnaoo aom Box 355 PinsDurgh Pemstvama 15230 0355 s

CAE-91-209 CCE-91-219 NS-0PLS-0PL-I-91-415 July 22, 1991 Mr. R. Pleniewicz, Station Manager Byron Nuclear Station Commonwealth Edison Company P.O. Box 458 4450 North German Church Road Byron, IL 61010

. amonwealth Edison Company yron/Braidwood Units 1 and 2 s

Relaxation of MSSV Setooint Tolerance to +/-3% - Revised SECL

Reference:

(1) Westinghouse letter CAE-90-315/CCE-90-310, dated 10-31-90.

Dear Mr. Pleniewicz:

Enclosed please find Revision 1 to safety evaluation SECL 90-469, previously transmitted via Reference 1. The revised safety evaluation clarifies safety valves.the section of the ASME code associated with the main steam If you have any questions, do not hesitate to call.

Very truly yours, t

l Y %.

B. S. Humphries, Manager tft N . I B. E. Rarig Comonwealth Edison Projects Enclosure Customer Projects Department cc: F. Lentine # '

O. Swartz P. McHale .e J. Feimster ' ' '

K. Kofron .

R. Waninski ,

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9610220382 910722 6(

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SECL 90-469 Rev.1 Customer

• Reference No(s).

N/A Westinghouse Reference No(s).

. ., N/A WESTINGHOUSE NUCLEAR SAFETY SAFETY EVALUATION CHECK LIST ,

1) NUCLEAR PLANT (S) : BYRON /BRAIDWOOD UNITS 1 4 2

2) SUBJECT (TITLE): RELAXATION OF MSSV SETPOINT TOLERANCE TO +/-3%

3) The written safety evaluation of the revised procedure, design change or modification required by 10CFR50.59 (b) has been prepared to the extent required and is attached. If a safety evaluation is not required or is incomplete for any reason, explain on Page 2.  :

Parts A and B of this Safety Evaluation Check List are to be completed only on the basis of the safety evaluation performed.

CHECK LIST - PART A 10CFR50.59(a)(1)

(3.1) L No_ A change to the plant as described in the FSAR? l

, (3.2) Yes _ No X A change to procedures as described in the FSAR? l (3.3) Yes_ No_L A test or experiment not described in the FSAR? *

(3.4) Yes_L No_ A change to the plant technical specifications?

(See note on Page 2.)

4) CHECK LIST - Part B 10CFR50.59(a)(2) (Justification for*Part B answers must be included on Page 2.)

(4.1) Yes_ No_L Will the probability of an accident previously '

evaluated in the FSAR be increased? l (4.2) Yes No_L Will the consequences of an accident previously evaluated in the FSAR be increased? l (4.3) Yes_ No_L May the possibility of an accident which is l different than any already evaluated in the FSAR l be created?

(4.4) Yes_ No_L Will the probability of a malfunction of equipment important to safety previously evaluated in the FSAR be increased?

(4.5) Yes_ No_T, Will the consecuences of a malfunction of equipment important to safety previously evaluated in the FSAR be increased?

(4.6) Yes_ No_L May the possibility of a malfunction of equipment important to safety different than any already evaluated in the FSAR be created?

(4.7) Yes_ No_L Will the margin of safety, as defined in the bases to any technical specifications be reduced?

1 I

l SECL 90-469 Rev. 1 3 NOTES:

If the answers to any of the above questions are unknown, indicate j- under 5) REMARKS and explain below.

If the answers to any of the above questions in Part A 3.4 or Part B cannot be answered in the negative, based on the written safety evaluation, the change review would require an application for license amendment as required by 10CFR50.59(c) and submitted to the NRC pursuant to 10CFR50.90.

5) REMARKS:

The followjng summarizes the justification based upon the written safety evaluation , for answers given in Part A 3.4 and Part B of this safety evaluation check list:

See Attached Evaluation 1

Reference to documents containing written safety evaluation:

FOR FSAR UPDATE -

Section: various Pages: Tables: Figures:

Reason for/[':scription of Change:

Table 15.0-2. Table 15.0-5. Fiaure 15.0-1. and Section 15.l?.3 were revised based on the new analyses (DT orotection and LOL/T"). -

6) SAFETY EVALUATION APPROVAL LADDER:

6.1) Prepared by (Nuclear Safety): A amA Date: 7/21I4l B.E.RariN / /

/27 h 6.2) Nuclear Safety Group Mana r: U Date

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BYRON /BRAIDWOOD UNITS 1 AND 2 i INCREASED MAIN STEAM SAFETY VALVE SETPOINT TOLERANCE l l SAFETY EVALUATION  ;

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1.0 BACKGROUND

y

! Commonwealth Edison Company (CECO) has found that over an operating  !

! cycle, the setnoint of the Main Steam Safety Valves (MSSV) changes by 4

more than 1% from the original set-pressure. As a result, the plant is placed in an ACTION statement and must take immediate steps to i

avoid a violation.

The Technical Specifications specify the setpoint at which the valves must open and the tolerance (in percent of the setpoint) within which

the valves must begin to lift when calibrated and/or tested. The i

specified tolerance of 1% of the setpoint, has proven to be difficult to meet when the valves are tested. Therefore, Ceco has requested 1

that Westinghouse perform an evaluation to support a relaxation in MSSV setpoint tolerances from 1% to 3% as defined in Technical Specification Section 3/4.7. This safety evaluation will address the

{ effects of the i3% tolerance on FSAR Accident analyses (non-LOCA, i LOCA, SGTR), the primary coa.ponent design transients, and the plant

! Overpressure Protection Report. The impact on the Main Steam System i and the MSSVs is not within Westinghouse scope of supply and is not j addressed in this evaluation.

! During normal surveillance, if the valves are found to be wif.hin i3%, j l they will be within the bases of the accident analyses. However, as

required per Reference 4, it is strongly recommended that the valves i be reset to the specified design tolerance (11%) to prevent future

! accumulation of drift beyond 3%. Resetting of the valves if the 1%

l tolerance is exceeded is consistent with the existing Technical  ;

j Specification requirements and the recommended Technical Specificatio,. j i modifications provided in Appendix D. Thus, this evaluation permits a .

j 13% setpoint tolerance to address as-found conditions. ,

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! The operation of the Class 2 main steam safety valves (MSSVs) is l

! governed by the ASME Code (Reference 2). Consenwealth Edison will i maintain the design basis of the MSSVs by ensuring that the valves, if l outside the 1% tolerance, will be recalibrated to within 1%. The i purpose of this evaluation is to provide a quantification of the effects of a higher as-found lift setpoint tolerance. The j .

l Overpressure Protection Report (Reference 3) documents how the effects are accounted f6 Fin the accident analyses and the acceptability of the increase in the lift setpoint tolerance. '

i

4 j 2.0 LICENSING BASIS 1 Title 10 of the Code of Federal Regulations, Section 50.59 (10 CFR 50.59) allows the holder of a license authorizing operation of a

. nuclear power facility the capacity to initiate certain changes, tests

] and experiments not described in the Final Safety Analysis Report (FSAR). Prior Nuclear Regulatory Commission (NRC) approval is not 2 required to implement the modification provided that the proposed i change, test or experiment does not involve an unreviewed safety

question or result in a change to the plant technical specifications incorporated in the license. While the proposed change to the MSSV 4

3

lift setpoint tolerances involves a change 'to the Byron and Braidwooc  !

-technical specifications and requires a licensing amendment request, j this evaluation uill be performed using the'~ method outlined under 1 10CFR50.59 to provide the bases for the determination that the  :

proposed change does not involve an unreviewed safety question. In l addition,-an. evaluation will demonstrate that the proposed change does i not represent a-e-ignificant hazards consideration, as required by 10CFR50.91 (a) (1) and will address the three test factors required by 10CFR50.92 (c).

3.0 EVALUATIONS The results of the various evaluations from the Nuclear Safety related disciplines within Westinghouse scope are discussed in the following sections.

3.1 Non-LOCA Evaluation 3.1.1 AT Protection The increase in the MSSV lift setpoint tolerance has the potential to impact the Overtemperature AT and Overpower AT setpoint equations. Referring to UFSAR Figure 15.0-1, increasing the point at which the MSSVs lift will lower the steam generator safety valve e line. If the current OTAT setpoint coefficients (K1 through K3) result in protection lines that just bound the thermal core limits, it is possible that by lowering the SG safety valve line to the right, a portion of the core limits will be uncovered.

In order to evaluate the effects of the increase in the setpoint tolerance, the Overtemperature AT and Overpower AT setpoint equations (K1 through K6) were examined to determine if the equations remained valid assuming that all 20 MSSVs opened with a +3%

tolerance. The results of that evaluation showed that there was .

sufficient ma gin in the generation of the current setpoint equations to offset the lowering of the SG safety valve line. The results of this calculation are presented as Figure 1.

3.1.2 DNB Events ,

l

! The ' transients identified in Table 1 are analyzed in the

Byron /Braidwood UFSAR to demonstrate that the DNB design basis is satisfied. With one exception, these events are a) of such a short i l duration that they do not result in the actuation of the MSSVs, b,'

core-related analyses that focus on the active fuel region only, or c) '

cooldown events which result in a decrease in secondary steam

pressure. The single exception is ;he loss of external load /tunbine trip event which is addressed explicitly in Section 3.1.7 of this

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evaluation. Thus, based on the above, these non-LOCA DNB transients are not adversely impacted by the proposed change, and the results and conclusions presented in the UFSAR remain valid.

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e nca. s DNB DESIGN BASIS TRANS2ENTS 4

.- . .U,EffI UFSAR Section FeedwaterSysteEMalfunction:

' 15.1.1 Reduction in Temperature d

Feedwater System Malfunction: -

15.1.2 Increase in Feedwater Flow 1

Excessive Increase in Secondary Steam Flow 15.1.3

Inadvertent Opening of a SG Relief 15.1.4 l or Safety Valve Steam System Piping Failure 15.1.5

(Double-Ended Rupture Core Response)

Partial Loss of Forced Reactor Coolant Flow 15.3.1 l Complete Loss of Forced Reactor Coolant Flow 15.3.2 S Reactor Coolant Pump Shaft Seizure 15.3.3 (DNB & Overpressurization Concerns) i Reactor Coolant Pump Shaft Break 15.3.4 i (DNB & Overpressurization Concerns) i Uncontrolled RCCA Bank Withdrawal 15.4.1 1 From a Subcritical Condition i

i Uncontrolled RCCA Bank Withdrawal 15.4.2 at Power -

RCCA Misalignment 15.4.3

)

Inadvertent Operation of the ECCS 15.5.1 4 Inadvertent Opening of a 15.6.1 j Pressurizer Safety or Relief Valve Startup of an In' active Reactor Coolant Pump 15.4.4 CVCS Malfunction (Boron Dilution) 15.4.6 4

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1 3.1.3 Dilution Events The following dilution events are analyzed to demonstrate that the

} operators (or the automatic mitigation circuitry) have sufficient time )

i to respor.d p.rior to reactor criticality once an alarm is generated.

3 The secondary syttom-is not modeled in the analysis of these events, '

and thus, changes to the MSSVs have no impact on these events.

l Therefore, the.results and conclusions presented in the UFSAR remain 3 valid. -

DILUTION EVENTS UFSAR Section J

i Startup of an Inactive Reactor 15.4.4 l Coolant Pump i

! CVCS Malfunction (Boron Dilution) 15.4.6 1

3.1.4 Steamline Break Mass & Energy Releases l For the steamline break mass and energy releases, the steam release j calculations are insensitive to the changes in the MSSV lift setpoints since the vast majority of these calculations result in i depressurizations of the secondary side such that the MSSVs are not i actuated. For the smaller break cases that might result in a heatup,

. based on the existing analyses one MSSV per steam generator is i

sufficient to provide adequate heat removal following reactor trip ar.d

is bounded by the MSSV assumption used in the current non-LOCA accident analyses. Thus, secondary pressures will be no greater than

those presently calculated.

i M UFSAR Section

Steamline Rupture Mass & Energy Releases 6.2.1.4 4

Inside Containment .

l Steamline Rupture Mass & Energy Releases WCAP-10961-P-A

] Outside Containment for Equipment i Environmental Qualification 4

! 3.1.5 Long-Tern Heat Removal Events 1

l The only non-LOCA transients remaining are the long-tem heatup j events. The long-ters heat removal events are ana' yzed to determine

! if the auxiliary feedwater (AFW) heat removal capability is sufficient i to ensure that the peak RCS and secondary pressures do not exceed i allowable limits, the pressurizer does not fill (LONF/LOACP), and the core remains covered and in a coolable geometry (FLB). These l

transients are listed below.

M UFSAR Section i 15.2.6 j Loss of Non-Emergency AC Power to Plant Auxiliaries (LOACP)

)

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__ _ _ _ _ . ~ _ __ _ _ _ _ _ _ _ _.__ _ __ _ _.._ _ _ _ _ _ .

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Loss of Normal Feeduater (LONF) 15.2.7 i *-

Feedwater System Pipe Break (FLB) 4 4

15.2.8 1 I These. transients are impacted by the increase in the MSSV lift

{- setpoint tol'erance because the calculations determining the amount of l AFW flow available must assume a maximum given steam generator i backpressure in order to determine the amount of AFW that can be i delivered. As the steam generator backpressure increases, the amount

{ of AFW delivered will be reduced. For the loss of non-emergency AC

! power and the loss of normal feedwater events, flow control valves in

! the AFW lines, designed to limit flow to a preset value, are assumed i

' to operate since they conservatively minimize the amount of AFW available for cooling. These transients assume an AFW flow rate of l 153 gpa per steam generator. If the valves were inoperable or failed 4

during operation, they would do so in the open position resulting in higher AFW flow rates. The valves will function such that the 153 gpm accident analysis assumption will be met independent of the increase in the generator backpressure.

j The feedline break event results in a faulted steam generator that depressurizes to atmospheric pressurt As a result, the AFW flow i control valves are assumed to fail, minimizing the amount of AFW j available for long-ters cooling. This assumption results in the AFW

! flow being preferentially fed to the faulted steam generator where it j is lost out the break. In order to ensure that some amount of AFW is i supplied to the remaining intact steam generators, passive orifice plates, installed in each of the AFW lines, are used to limit the flow I

to the faulted loop. Since there is no method available to throttle i AFW flow, the overall flow provided to the intact steam generators i during a feedline break event will be reduced as the backpressure

! increases. Therefore, the effects of the MSSV setpoint tolerance

{ relaxation on AFW performance during a feedline break accident must be l considered.

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! A calculation was performed to determine the maximum steam pressure 1 inside an intact steam generator during the long-term cooling portion

{ of the transient (i.e., after steamline isolation occurs). The i results showed that the maximum steam pressure at Byron and Braidwood i is 1250 psia. Note that this value bounds both cases with and without i offsite power available. Based on subsequent calculations, it was

! determined that the resultant AFW flow (458 gpa to the three intact i steam generators) will remain greater than that currently assumed in

! the licensing-batis feedline break analysis (420 gpe). Therefore, the results and conclusions presented in the UFSAR (15.2.8) remain valid.

The final concern is the potential for steam generator .

overpressurization following reactor trip for the other long-term heatup events. Based on the existing UFSAR loss of non-emergency AC power and loss of normal feedwater analyses, long-term cooling requires a maximum of 1-3% of nominal plant steam flow from each steam generator or a plant total of 4-12% of nominal steam flow (depending on the transient). In order to pass the required flow, the two lowest set MSSVs would be required to lift. With a 3% lift tol.erance, this 7

rw - ,- - n-- e

l condition could result in full open pressures for the two valves of 1249.5 and 1265.3 psia, respectively. The relief capacity of the first 2 MSSVs full opsn on each steam generator bounds 12% nominal steam flow. Thus, the steam flow requirement would be satisfied and

, resultant steam pressure of -1265 psia would not exceed 110% of the i secondary design pressure (1320 psia). As discussed above, the

, maximum expe'eted. pressure for a feedline break event is 1250 psia

which is also less than the limit. Therefore, the proposed change

! does not adversely impact the long-term cooling overpressurization requirements.

! Thus, based on the discussions presented above, only one UFSAR l transient is impacted such that a new analysis must be performed in i order to address the effects of the MSSV lift setpoint tolerance

increase from 1% to 13%. This event is the loss of external 1

load / turbine trip accident. For the remaining transients, the results j and conclusions presented in the Byron /Braidwood UFSAR remain valid.

! 3.1.6 -3% Tolerance l Secondary steam releases are generated for the offsite dose i calculations for the following non-LOCA transients: the steam system  :

piping failure (UFSAR Table 15.1-3), the loss of external load (UFSAR l Table 15.2-4), and the RCP shaft seizure (locked rotor - UFSAR Table 4 i 15.3-3). The methodology used to calculate these masses is based on I determining the amount of secondary side inventory required to cool ,

l down the RCS. During the first two hours (0-2 hours), the operators

are assumed to lower the RCS average temperature to no-load conditions

(557'F) by bleeding steam. Over the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (2-8 hours), the

! operators will cool the plant down such that Mode 4 operation (hot shutdown) can be entered.

j ine existing steam release calculations for the 0-2 hour period used enthalpies corresponding to saturated conditions at both the nominal

! full power RCS average temperature and the no-load temperature (588'F and 557'F, respectively). Thus, as long as the i

i increased lift setpoint tolerance (-3%) does not result in the MSSVs i remaining open at a scturation temperature outside of the range identified above, the existing mass releases remain valid.

{

• The existing mass release calculations were performed using the temperatures previously identified (588'F and 557'F). Per the

! Byron /Braidwood Technical Specifications, the lowest set MSSV on each l steam generator will open at 1190 psia (1175 psig) not including any i

tolerance. Based on the ASME Steam Tables (Reference 6) at saturated conditions, 557'F corresponds to 1106.4 psia and represents the lowest steam pressure considered in the mass calculations. Thus, the existing releases include a ressat pressure equal to 7% below the lowest "echnical Specification itft setpoint. As long as the valves continue to ressat within this pressure range, the current mass releases remain valid. .

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i 3.1.7 Analysis Summary 3.1.7.1 Loss of External Load / Turbine Trip l

! The . loss of external load / turbine trip event is presented in Section '

l 15.2.3 of The pyron/Braidwood UFSAR. This transient is caused by a

turbine-generator trip which results in the innediate termination of l j steam flow. Since no credit is taken for a direct reactor trip on i turbine trip, primary and secondary pressure and temperature will begin to increase, actuating the pressurieer and steam generator i safety valves. The reactor will eventually be tripped by one of the i other reactor protection system (RPS) functions; specifically, l overtemperature AT, high pressurizer pressure, or low-low steam i

4 generator water level.

i The turbine trip event is the limiting non-LOCA event for potential

overpressurization, i.e., this transient forms the design basis for

! the primary and secondary safety valves. Since the MSSVs will now l

! potentially be opening at a higher pressure due to the increase in j the lift setpoint tolerance, it is necessary to analyze this  ;

i transient in order to demonstrate that all the applicable acceptance I l criteria are satisfied. A turbine trip is classified as an ANS '

l condition II event, a fault of moderate frequency. As such, the i appropriate acceptance criteria are DNBR, peak primary pressure, and l peak secondary pressure. The transient is described in greater detail in the UFSAR.

The turbine trip event is analyzed using a modified version of tne LOFTRAN digital computer code (Reference 7). The program simulates neutron kinetics, reactor coolant system, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generators, and main steam safety valves. With the modified code, the MSSVs are explicitly modeled as a bank of 5 valves on each steam generator with staggered lift setpoints. Since higher steam pressures are conservative for this event, no blowdown or hysteresis behavior was -

assumed.

Consistent with the aristing UFSAR analysis, the following assumptions were used in this analysis:

a. Initial power, temperature, and pressure were at their nominal values consistent with ITDP methodology (WCAP-8567).

b. Turbine trip was analyzed with both minimum and maximum reactivity feedback corresponding to beginning-of-life and end-of-life conditions, respectively.

c. Turbine trip was analyzed both* with and without pressurizer pressure control. The PORVs and sprays were assumed operable in the cases with pressure control. The cases with pressure control minimize the increase in primary pressure which is conservative for the DNBR transient. The cases without pressure control maximize the increase in pressure which is conservative for the RCS overpressurization criterion. -

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d. The stea3 generator PORY and steam du p valves r:ere not assumed operable. This assumption ::axinizes fecondary pressure.

l e. Main feedwater flow was assumed to be lost coincident with the l

turbine trip. This assumption maximizes the heatup effects, i f. Only the overtemperature AT, high pressurizer pressure, and i' low-low steam generator water level reactor trips were assumed operable for the purposes of this analysis. _

, g. The MSSVs were assumed to lift 3% above the Technical i Specification setpoints and were assumed to be full open 5% above the setpoints. This is consistent with the 2% difference between l

lift and rated flow currently included in the code.

! h. An individual MSSV was assumed to have a full flow capacity of

! 249 lbm/sec.

e l 3.1.7.2 Analysis Results i

j Four cases were analyzed: a) minimum feedback without pressure

control, b) maximum feedback without pressure control, c) maximum

feedback with pressure control, and d) minimum feedback with

! pressure control. The calculated sequence of events for the four

! cases is presented in Table 2.

i Case A: -

Figures 2 through 4 show the transient response for the turbine trip event under 80L cor.ditions without pressure control. The reactor is tripped on high pressurizer pressure. The neutron flux remains essentially constant at full power until the reactor is tripped, and the DNBR remains above the initial value for the duration of the transient. The pressurizer safety valves are actuated and maintain ,

primary pressure below 110% of the design value. The main steam safety valves are also actuated and maintain secondary pressure below 110% of the design value.

Case B:

Figures 5 through 7 show the transient response for the turbine trip event under E0L conditions without pressure control. The reactor is tripped on high pressurizer pressure. The DNBR increases throughout the transient"and never drops below the initial value. The pressurizer safety valves are actuated and maintain primary pressure below 1105 of the design value. The main steam safety valves are also actuated and maintain secon4nry pressure below 110% of the design value.

Case C: .

Figures'8 through 10 show the transient response for the turbine trip event under EOL conditions with pressure control. The reactor is tripped on overtemperature AT. The DN8R increases throughout the transient and never drops below the initial value. The 10

pressurizer relief valves and sprays aaintain primary pressure below 110% of the design value. The main stean safety valves are also actuated and maintain secondary pressure'below 110% of the design val ue .

Case.D:..

Figures 11 thro' ugh 13 show the transient response for the turbine trip event under BOL conditions with pressure control. The reactor is tripped on overtemperature AT. The neutron flux remains essentially constant at full power until the reactor is tripped, and although the DNBR value decreases below the initial value, it remains well above the limit throughout the entire transient. The pressurizer relief valves and sprays maintain primary pressure below 110% of the design value. The main steam safety valves are also i

actuated and maintain secondary pressure below 110% of the design

, value. '

3.1.7.3 Analysis Conclusions  !

Based on the results of these turbine trip analyses with a +3%

tolerance on the MSSV lift setpoints, all of the applicable

, acceptance criteria are met. The minimus DNBR for each case is greater than the limit value. The peak primary and secondary pressures remain below 110% of design at all times.

4 i

i l

f I

e 6

11

+ l

. TABLE 2 l TURBINE TRIP SEQUENCE OF EVENTS TIME

! ACCIDENT U.DE litil

j. Without pressurizer Turbine trip, loss of main 0.0 ,

feedwater flow j control (minimum reactivity feedback)

High pressurizer pressure 4.3 l

, reactor trip setpoint i reached Rods begin to drop 6.3 Initiation of steam release 6.5 j from the MSSVs I

. Peak pressurizer pressure 7.5 1

occurs j Minimum DNBR occurs (1) i

Without pressurizer Turbine tria, loss of main 0.0 i control (maximum feedwater flow reactivity feedback)

High pressurizer pressure 4.3 reactor trip setpoint reached Rods bagin to drop 6.3 Initiation of steam release 6.5 from the MSSVs Peak pressurizer pressure 7.0 occurs Minimum DNBR occurs (1) 4 (1) DNBR does not decrease below its initial value.

e 12

miuunnnq

. TABLE 2 (continued) ,

, TURBINE TRIP SE00ENCE OF EVENTS TIME ACCIDENT EY.Dil lif&l With pressurizer Turbine trip, loss of main. 0.0 control (maximum feedwater flow reactivity feedback)

Initiation of steam release 6.5 from the MSSVs Overtemperature AT 7.4 reactor trip setpoint reached Peak pressurizer pressure 7.5 occurs Rods begin to drop 9.4 Minimum DNBR occurs (1)

With pressurizer - Turbine trip, loss of main 0.0 control (minimum feedwater flow reactivity feedback)

Initiation of steam release 6.5 from the MSSVs -

Overtemperature AT 6.9 reactor trip setpoint reached Rods begin to drop 8.9 Minimum DNBR occurs 10.0 Peak pressurizer pressure 10.5 occurs d

(1) DNBR does not decrease below its initial value.

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3.1.8 Overpressure Protection Report "

The Overpressure Protection Report (Referlmce 3) is published to '

demonstrate that the limiting ANS Condition II pressurization transient (loss of load / turbine trip) does not result in primary and secondary pressures in excess of 110% of the design values. The Overpressure Protection Report has been reviewed as part of this safety evaluation. In order to determine the effects of the increases in the lift setpoint tolerances, the loss of load / turbine trip transient presented in the Overpressure Protection Report was analyzed. The new analysis was performed tonsistent with the existing report with the exception of the explicit MSSV modeling described in the LOFTRAN description above. The results of this analysis demonstrated that the peak RCS pressure, assumed to be at the outlet of the reactor coolant pumps, was below the limit value (2750 psia).

With respect to the secondary steam system, the transient analysis resulted in approximately 60% of the total MSSV relief capacity being used. It also showed that the maximum secondary steam pressure was less than the limit (1320 psia). Thus, the conclusions presented in the Overpressure Protection Report remain valid. Changes to this report are included in this report.

3.1.9 Non-LOCA Conclusions '

. The effects of increasing the as-found lift setpoint tolerance on the main steam safety valve have been examined, and it has been determined that, with one exception, the current accident analyses as presented in the UFSAR remain valid. The loss of load / turbine trip 4

event was analyzed in order to quantify the impact of the setpoint tolerance relaxation. As previously demonstrated in this evaluation, all applicable acceptance criteria for this event have been satisfied and the conclusions presented in the UFSAR are still valid. Thus, the proposed Technical Specification change does not constitute an ,

unreviewed safety question, and the non-LOCA accident analyses, as presented in the report, support the proposed change.

Changes to the UFSAR and the Overpressure Protection Report are included in this safety evaluation as appendices.

3.2 LOCA and LOCA Related Evaluations The effects of' increased tolerances for the Main Steam Safety Valve (MSSV) setpoints on the LOCA safety analyses has been previously performed for VANTAGE 5 fuel. The current Technical Specification setpoints with rated flow is gives below for easy reference. The effect of either increasing or decreasing the setpoint by 3%,

depending upon the direction of conservatism, has been evaluated for the LOCA analyses.

MSSV NUMBER T/S SETPOINT RAIED F10ll ACTUAL FLOW MS017A,8,C,D 1190 (PSIA) 841,427 934,918 4

14 4

. M5016A,B,C,0 1205 (PSIA) 852,0p 946,710 M5015A,B,C,D 1220 (PSIA) 862,652 2

958,502 MS014A,,B,C,0 1235 (PSIA) 873,265 970,294 M5013A,B,[D 1250 (PSIA) 883,878 982,087 Rated flow should be used for heat-up accidents and actual flow shculd be used for cooldown accidents. The following presents the effect of the proposed setpoint revision from 1% to 3% on the LOCA-related analyses.

3.2.1 Large Break LOCA (FSAR Chapter 15.6.5) 4 Calculations performed to determine the response to a hypothetical i large break LOCA do not model the MSSVs, since a large break LOCA is characterized by a rapid depressurization of the reactor coolant i

', system primary below the pressure of the steam generator secondaries. Thus, the calculated consequences of a lar

' are not dependent upon assumptions of MSSV performance. Therefore, ge break LOCA the large break LOCA analysis results are not adversely affected by the proposed revised MSSV setpoint tolerances.

3.2.2 Small Break LOCA (FSAR Chapter 15.6.5) i Small Break LOCAs are dependent upon heat transfer from the Reactor Coolant System (RCS) primary to the steam generator secondary in order to limit the consequences of the accident. A period exists when the RCS primary pressure hangs above the steam generator

' secondary pressure and excess decay heat is transferred to the steam

, generators. Since a loss of offsite power is assumed to occur coincident with the small break LOCA, the steam dump system and power

' operated relief valves are assumed to be inactive. Thus, steam .

relief from the steam generator secondaries takes place through the MSSVs.

l The small break LOCA analyses presented in Appendix C of the Byron /Braidwood Stations Units 1 and 2 VANTAGE 5 Reload Transition

! Safety Report were performed using a 3% higher safety valve setpoint pressure. The standard 3% accumulation

, full flow was also accounted for in the,between analyses. valve actuation These and analyses  !

calculated peak cladding temperatures well below the allowed 2200 0F limit as specified in 10CFR50.46. demonstrating that the proposed J change to the MSSV technical specification can be accommodated for small break LOCAs.

4 j A reduction in the MSSV setpoint tolerance would act to lower the I i secondary pressure. Since the RCS pressure is controlled by the steam generator secondary pressure through the MSSVs, a decrease in secondary pressure would also result in a lower RCS pressure. A lower RCS pressure would result in more safety injection flow

delivered to the RCS. As such, the -3% MSSV setpoint tolerance would i provide increased safety injection water to the RCS. wMich would act

to reduce the calculated peak clad temper 4ture. Therefore, t -3%-

MSSV setpoint tolerance would not adversely affect the small break LOCA analysis results.

15

While the PCT has increased due to the revised +3% MSSV setpoint 3 tolerance, the calculated PCT remains below 22000F. Therefore, it i

is concluded that the increase in the MSSY'setpoint tolerances limit 3 to plus or minus 3 percent does not adversely affect the small break l LOCA analysis results.

! 3.2.3 LOCA Blow 66wn Reactor Vessel and RCS Loop Forces

!- (FSAR Chapter 3.9)

The licensing basis LOCA hydraulic forces analysis results found in the FSAR calculate that the peak loads occur within the first 500 i milliseconds of the transient. This occurrence is well before any l automatically operated safety feature has responded to the LOCA and before steam generator pressures could reach the set-pressures of the MSSVs. Therefore, changes in the MSSV Technical Specification 1

set-pressures do not change the calculated consequences appearing in the FSAR.

4 3.2.4 LOCA Mass and Energy Releases for Containment Integrity Analyses l (FSAR Chapter 6.2)

There is no effect due to increasing the tolerance of the steam generator Main Steam Safety Valve (MSSV) setpoints from 11% to 3% on j

short or long tern LOCA mass and energy release and the resulting containment integrity response. Since a large break LOCA rapidly decreases the RCS pressure below that of the steam generator secondary

{ pressure, the philosophy for long term LOCA considerations is to

release all steam generator' metal energy and primary coolint to i

containment. Therefore, only secondary to primary heat transfer is

! important in determining the amount of energy released to

! containment. Benefits from any mechanisms, such as MSSVs, that may possibly reduce the amount of available steam generator stored energy are small. Therefore, MSSVs are not modeled in the analysis performed

! to calculate the consequences for the long tem design basis LOCA j event. .

l The short term mass and energy release calculation is terminated after a few seconds. This time duration is so short as to preclude any i appreciable effect due to either secondary to primary heat transfer or l potential MSSV actuation.

! 3.2.5 Steam Generator Tube Rupture (FSAR Chapter 15.6.3) l For the steam generator tube rupture (SGTR) event, the FSAR analysis l was performed to evaluate the radiological consequences. The major

! factors that affect the radiological doses are the amount of primary j coolant transferred to the secondary side of the ruptured steam 4 generator through the ruptured tubet the steam released from the, i ruptured steam generator to the atmosphere and the amount of i radioactivity in the reactor coolant. The impact on these parameters l of changing the main steam safety valve setpoint tolerance from 1% to j 3% has been detemined.

l For the FSAR SGTR analysis, the loss of inventory due to.the tube j rupture results in a decrease in pressurizer pressure. Reactor trip

,i 4

16 h .

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'ibs5'ofoffsitepowerSasalsoassumedt6Ecc~r'atthet$e'of u )

e reactor trip, thus the stea:t dump system t:as assumed to be l unavailable. The energy transfer from the' primary system following reactor and turbine trip causes the secondary side pressure to j increase rapidly after reactor trip until the steam generator power i operated' relief' valves (PORVs) and/or safety valves lift to dissipate

the energy. For'the SGTR analysis, it was assumed that the secondary l pressure is maintained at the lowest secondary safety valve setpoint

following reactor trip. After reactor trip and SI initiation, the RCS pressure was assumed to reach equilibrium at the point where the

incoming SI flowrate equals the outgoing break flowrate, and the l 1

equilibrium pressure and break flowrate were assumed to persist until l 30 minutes after the accident. A change in the main steam safety

valve setpoint tolerance to -3% will result in the secondary pressure i being maintained at a lower pressure during this 30 minute period, i thereby increasing the primary to secondary pressure differential.

i i

This will result in an increase to the primary to secondary break flow  !

and the atmospheric steam release via the ruptured steam generator.

f l An evaluation was performed to determine the effect of decreasing the i safety valve setpoint by -3% with respect the SGTR analysis in the l FSAR. It is noted that this evaluation was performed in conjunction

! with the other changes associated with the VANTAGE-5 fuel upgrade, L specifically 15% steam gen rator tube plugging and a hot leg

! temperature range of 618.4 F to 600.0'F. The results of the

evaluation indicated that the break flow increases slightly but is

! still less than the conservative value reported in the FSAR lor the

. SGTR event by approximately 25. It is noted that the reactor coolant i activity assumed for the SGTR analysis in the FSAR is based on 1% fuel i defects and is assumed to be independent of the transient conditions.

! Therefore this assumption would not be affected by the aforementioned j changes.

j A radiological analysis using the revised mass releases was completed i which indicates that the slight increase in the steam release is .

! offset by the margin in the primary to secondary break flow (which

, exists in the FSAR report), such that the offsite radiation doses are less than the results reported in the FSAR. Therefore, it is '

i concluded that a change in the MSSV setpoint tolerance from 1% to 3%

will not increase the consequences of a SGTR as reported in the FSAR.

l 3.2.6 Hot Leg Switchover of the ECCS to Prevent Potential Baron

! Precipitation (FSAR Chapter 6.3.2.5) .

The calculations performed to determine the time (post-LOCA) at which

! the boron concentration in the reactor vessel would exceed the

! solubility limit do not require modeling of the main steam safety i

valves. However, an evaluation is pequired to assure that adequite j ECCS flow is provided to prevent boron precipitation following the

! switchover to hot leg recirculation. The minimum time for hot leg

! switchover for the Byron /Braidwood Stations was calculated to be 18

{ hours based on large break LOCA assumptions. The calculated core i

I

) 17

boil-offrateat18hsurswouldbeapproxiniately20lbm/sec. The minicum ECCS flow required for delivery to the hot legs following switchoveris1.5timestheboil-offrate.loralargebreakLOCAor approximately 30 lbm/sec. The RCS pressure for a small break LOCA at the hot leg switchover time of 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> can conceivably be as high as the highest. steam generator safety valve setpoint (approximately 1250 psia plus 3%). -conditions for a small break LOCA differ significantly from those for a large break LOCA such that the requirements to prevent boron precipitation are much less restrictive than those for a large break LOCA. Thus, under small break LOCA conditions, ECCS flow to both the hot and cold legs can be considered in satisfying the boil-off requirement. Thus the charging and safety injection pumps must meet or exceed 30 lbs/sec at 1288 psia in order to satisfy the boil-off requirement for a small break LOCA. A review of the ECCS shows that the safety injection pumps, when aligned in the hot leg recirculation mode, can deliver more than the required 30 lba/sec at an RCS pressure of 1288 psia. Thus, the proposed change to the MSSV Technical Specification setpoint pressure tolerance from 1% to 13%

will not alter the results or conclusions appearing in the FSAR regarding the switchover of the ECCS to hot leg recirculation.

3.2.7 Post-LOCA Longterm Core Cooling (FSAR Chapter 15.6.5)

Since the post-LOCA subcriticality is based on large break requirements, deviations in MSSV set-pressures do not effect the boron concentration in the containment sump post-LOCA. Thus, the proposed change to the MSSV Technical Specification setpoint pressure tolerance from 1% to 13% will not alter the results or conclusions regarding the ability to keep the reactor cores subcritical on the boron  ;

provided by the ECCS.

3.2.8 LOCA Conclusions The effect of a increase in the allowable Nain Steam Safety Valve set pressure tolerance from 1% to t 3% on the FSAR LOCA analysis has been -

evaluated. In each case the applicable regulatory or design limit was satisfied. Specific analyses were perfonned for small break LOCA assuming the current MSSV Technical Specification set pressures plus the proposed additional 3% uncertainty. The calculated peak cladding temperatures were well below the 10 CFR 50.46 22000F limit.

3.3 Containment Intearity Evaluation Neither the masPand energy release to the containment following a postulated loss of coolant accident (LOCA), nor the containment response following the LOCA analysis, credit the MSSV in mitigating the consequences of an accident. Therefore, changing the MSSV lift"setpoint tolerances would have no impact on the containment integrity analysis.

In addition, based on the conclusion of the transient analysis, the change to the MSSV tolerance will not affect the calculated steamline break mass and energy releases inside containment. Consequently, the main steam line break containment integrity analysis is not impact by the change to the MSSV setpoint tolerances. ,

18 l

I

3, 4 E0P Evaluation In the Emergency Operating Procedures (EOPs)', the MSSV setpoint pressures are used to determine when to trip the reactor coolant pumps (RCPs). .The determination is conservative, taking into account instrument uncertiainties. The conservatism, along with the small difference between the MSSV pressure used to determine the RCP trip setpoint for the E0Ps and the in-plant first lift pressures of less than 5.6% leads to the conclusion that there is no significant impact on the E0Ps in this area. -

The MSSV pressures are also used in the E0Ps on the heat sink status

tree in determining which heat sink E0P is appropriate for implementation. These pressures are only involved in optional or yellow paths on the heat sink status tree. This means that the plant condition is such that the operator is not required to perform the heat sink E0Ps called for by these yellow paths. Consequently, an inappropriate -

transition to these procedures would not cause the operator to forego an action required to maintain the plant in a safe condition. Thus, the i variations found between the E0P MSSV setpoints'and the MSSV in-plant lift pressures have negligible impact on the E0Ps in this area. If the set pressures are within 5%, use of these procedures will ensure that the secondary pressure remains within acceptable limits.

4.0 DETERMINATION OF UNREVIEWED SAFETY QUESTION i

1. Will the probability of an accident previously evaluated in the SAR be increased?

The 3% tolerante on the MSSV setpoint does not increase the probability of an accident peeviously evaluated in the FSAR. There are no hardware modifications to *.he valves. Therefore..there is not an increase in the spurious opening of a MSSV. The MSSVs are actuated after an accident is -

initiated to protect the secondary systems from overpressurization.

Sufficient margin exists between the normal steam system operating i

pressure and the valve setpoints with the increased tolerance to preclude an increase in the probability of actuating the valves. l Therefore, the probability of an accident previously evaluated in the FSAR would not be increased as a result of increasing the MSSV lift setpoint tolerance by 3% above or Delow the current "echnical Specification value.

\

2. Will the consequences of an accident previously evaluated in the SAR be increased? ,

l All of the applicable LOCA and non-LOCA design basis acceptance criteria

~

remain valid both for the transients evaluated and the single event analyzed. Additionally, no new limiting single failure is introduced by the proposed change. The DNBR and PCT values remain within the 4

specified limits of the licensing basis. Although increasing the valve l

setpoint will increase the steam release from the ruptured steam generator above the FSAR value by approximately 25, the SGTR analysis Ig

_ - - g -

Indicates that the calculated Dreak flow is still less tnan the value reported in the FSAR. Therefore, the radiological analysis indicates that the slight increase in the steaa release is offset by the decrease in the break flow such that the offsite radiation doses are less than those reported in the FSAR. The evaluation also concluded that the existing mass releases used in the offsite dose calculations for the remainig tr'ansiants .(i.e., steamline break, rod ejection) are still applicable. Therefore, based on the above, there is no increase in the dose releases.

3. May the possibility of an accident which is different than any already evaluated in the SAR be created?

The 3% tolerance on the MSSV setpoint does not create the possibility of an accident which is different than any already evaluated in the FSAR. Increasing the lift setpoint tolerance on the MSSVs does not introduce a new accident initiator mechanism. No new failure modes have been defined for any system or component important to safety nor has any new limiting single failure been identified. No accident will be created that will increase the challenge to the MSSVs and result in increased actuation of the valves. Therefore, the possibility of an accident different than any already evaluated is not created.

4. Will the probability of a malfunction of equipment impo> tant to safety previously evaluated in the SAR be increased?

Although the proposed change takes place in equipment utilized to prevent overpressurization on the secondary side and to provide an additional heat removal path, increasing the as-found lift setpoint tolerance on the MSSVs will not adverse:y affect the operation of the reactor protection system, any of the protection setpoints, or any other device required for accident mitigation.

5. Will the consequences of a malfunction of equipment important to safety previously evaluated in the SAR be increased?

No, as discussed in the response to Questions 2, there is no possibility of increasing the dose releases as a result of increasing the as-found lift setpoint tolerance on the MSSVs as defined in the attached safety evaluation.

6. May the possibility of a malfunction of equipment important to safety different than any already evaluated in the SAR be created?

No, as discussed in Question 4, an increase in the as-found lift setpoint tolerance on the MSSVs will not impact any other equipment important to safety. ,

20 1

l 7. Will the margin of safety as defined in the' bases to any technical j specification be reduced? .

j No, as discussed in the attached safety evaluation, the proposed l

i increase in the as-found MSSV lift setpoint tolerance will not invalidate the LOCA and non-LOCA conclusions presented in the UFSAR accident analyses. The new loss of load / turbine trip analysis concluded '

i that all applicable acceptance criteria are still satisfied. For all r i

the UFSAR non-LOCA transients, the DNB design basis, primary and secondary pressure limits, and dose release limits continue to be met.

! Peak cladding temperatures remain well below the limits specified in 10CFR50.46. Thus, there is no reduction in the margin to safety.

l

5.0 CONCLUSION

S 1

! The proposed change to main steam safety valve lift setpoint i tolerances from 1% to 23% has been evaluated by Westinghouse. The I

preceding analyses and evaluations have determined that operation with

! the MSSV setpoints within a 3% tolerance about the nominal values l will have no adverse impact upon the licensing basis analyses, as well as the steamline break mass & energy release rates inside and outside of containment. In addition, it is concluded that the 13% tolerance i

on the MSSV setpoint does not adversely affect the overpower or overtemperature protection system. As a result, adequate protection i to the core limit lines continues to exists. Therefore, all licensing i basis criteria continue to be satisfied and the conclusions in the

,' FSAR remain valid.

The recommeaded Technical Specification and FSAR changes, along with a j no significant hazards evaluation, are presented as attachments to j this evaluation.

! Based on the information presented above, it can be concluded that the -

i proposed increase of main steam safety valve lift setpoint tolerances i from t1% to 13% does not represent an unreviewed safety question per

, the definition and requirements defined in 10 CFR 50.59.

I j

6.0 REFERENCES

i

1) Byron /Braidwood Technical Specifications through Amendments 37 and 23,

respectively.

! 2) ANSI /ASME BPV-III, "ASME Boiler and Pressure Vessel Code - Sectisn III l Rules for Construction of Nuclear P6wer Plant Components," ASME,1983. 1 l 3) CAW-3581/C8W-3009," Commonwealth Edison Company, Byron and Braidwood j Stations - Units 1 and 2 Overpressure Protection Report," July 1981.

4) ANSI /ASME OM-1-1981, " Requirements for Inservice Performance Testing i of Nuclear Power Plant Pressure Relief Devices," ASME, 1981 1

i

)

i j 21 l

l

5) " Byron /Braidwood Stations Units 1 & 2 Updated Final Safety Analysis Report (UFSAR), D:cket Numbers 50-454, 455,"456, and 457, December 1989. .

6) ASME Steam Tables, Fifth Edition,1983.

7) Burnett, T.W.T.7'et al ., "LOFTRAN Code Description," WCAP-7907-P-A, '

1 June 1972.

8) Chelemer, H. et al.," Improved Thermal Des 190 Procedure,"

WCAP-8567-P-A, February 1989.

9) DiTommaso, S.D. et al.," Byron /Braidwood That Reduction Final Licensing Report," WCAP-11386-P, Revision 2, November 1987. ,

10) Butler, J.C. and D.S. Love,"Steamline Break Mass / Energy Releases for Equipment Environmental Qualification outside containment," l WCAP-10961-P, October 1985.

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Westinghouse Energy Systems Ba 355 Electric Corporation "*0 P"*88 423"3" Mr. R. Pleniewicz, Station Manager CAE-90-315 Byron Nuclear Station CCE-90-310 Commonwealth Edison Company NS-OPLS-OPL-1-90-619 P.O. Box 458 October 31, 1990 4450 North German Church Road Byron, IL 61010 Comonwealth Edison Company Byron /Braidwood Units 1 and 2 Relaxation of MSSV Setooint Tolerance to +/-3%

Dear Mr. Pleniewicz:

Enclosed please find the safety evaluation performed by Westinghouse in accordance with the criteria of 10 CFR 50.59 which concludes that the proposed relaxation of main steam safety valve lift setpoint tolerances from 1% to 3%

does not involve an unreviewed safety question.

The recomended Technical Specification revisions are provided as Appendix D to the safety evaluation. A significant hazards evaluation to support the recommended changes is included as Appendix C.

Westinghouse recomends resetting the valve; to within the design tolerance of 1% consistent with ASME Code, Section 11 reeirements. In order to relax this requirement, the valve manufacturer must concur with the change to the design basis tolerance specified for the valves in quest en.

This submittal represents the final version of the safety evaluation and supporting documentation. However, Westinghouse will resolve any additional coments or questions from Commonwealth Edison concerning the enclosed evaluation.

Please take a few minutes to complete the enclosed Quality Survey Form. If you have any questions, do not hesitate to call.

Very truly yours,

,ed h G. P, Voth, Manager B. E. Rarig Cor,nonwealth Edison Projects Enclosure Customer Projects Department

SECL 90-469 Customer Reference No(s).

M/A Westinghouse Reference No(s).

N/A WESTINGHOUSE NUCLEAR SAFETY SAFETY EVALUATION CHECK LIST

1) NUCLEAR PLANT (S) : BYRON /BRAIDWOOD UNIT 5 1 1 2

2) SUBJECT (TITLE): RELAXATION OF MSSV SETPOINT T0LERANCE TO +/-3%

3) The written safety evaluation of the revised procedure, design change or modification required by 10CFR50.59 (b) has been prepared to the extent required and is attached. If a safety evaluation is not required or is incomplete for any reason, explain on Page 2.

Parts A and B of this Safety Evaluation Check List are to be completed only on the basis of the safety evaluation performed.

CHECK LIST - PART A 10CFR50.59(a)(1)

(3.1) Yes l No A change to the plant as described in the FSAR?

(3.2) Yes No 1 A change to procedures as described in the FSAR?

(3.3) Yes No 1 A test or experiment not described in the FSAR?

(3.4) Yes X No A change to the plant technical specifications?

(See note on Page 2.)

4) CHECK LIST - Part B 10CFR50.59(a)(2) (Justification for Part B answers .

must be included on Page 2.)

(4.1) Yes No1 Will the probability of an accident previously evaluated in the FSAR be increased?

(4.2) Yes__ No 1 Will the consequences of an accident previously i evaluated in the FSAR be increased?

(4.3) Yes_ No 1 May the possibility of an accident which is different than any already evaluated in the FSAR be created?

(4.4) Yes _ No1 Will the probability of a malfunction of equipment important to safety previously evaluated in the FSAR be increased?

(4.5) Yes _ No1 Will the consequences of a malfunction of equipment important to safety previously evaluated in the FSAR be increased?

(4.6) Yes No1 May the possibility of a malfunction of equipment important to safety different than any already evaluated in the FSAR be created?

(4.7) Yes No1 Will the margin of safety as defined in the bases to any technical specifications be reduced? .

1 i

. ~. . _ _ _ _ __ _ -_ _ ___ _ _ _ _ _ _ . _ _ ._ _ _ _ _ . _ _ _ . _ . . . _ - _

h s.

l SECL 90-469 NOTES:

If the answers to any of the above questions are unknown, indicate under 5) REMARKS and explain below.

If the answers to any of the above questions in Part A 3.4 or Part B 1 cannot be answered in the negative, based on the written safety evaluation, the change review would require an application for license amendment as required by 10CFR50.59(c) and submitted to the NRC

pursuant to 10CFR50.90.

l l l 5) REMARKS:

i Thefollow{ngsummarizesthejustificationbaseduponthewrittensafety ,

! evaluation , for answers given in Part A 3.4 and Part B of this safety l l

evaluation check list: l i

See Attached Evaluation l

1 Reference to documents containing written safety evaluation:

FOR FSAR UPDATE Section: various Pages: Tables: Figures:

Reason for/ Description of Change:

Table 15.0-2. Table 15.0-5. Fiaure 1Fi.0-1. and Section 15.2.3 were l revised based on the new analyses (D" orotection and LOL/TT).

6) SAFETY EVALUATION APPROVAL LADDER:

6.1) Prepared by (Nuclear Safety): d Man'- Date:m/Ao/9o ' '

B. E. Rarig /

6.2) Nuclear Safety Group Manager: Date: 3 f*

R.J./Sterdis U

i 2

BYRON /BRAIDWOOD UNfTS 1 AND 2 INCREASED MAIN STEAM SAFETY VALVE SETP0' INT TOLERANCE SAFETY EVALUATION

~~

1.0 BACKGROUND

Commonwealth Edison Company (Ceco) has found that over an operating cycle, the setpoint of the Main Steam Safety Valves (MSSV) changes by more than 1% from the original set-pressure. As a result, the plant is placed in an ACTION statement and must take immediate steps to avoid a violation.

The Technical Specifications specify the setpoint at which the valves must open and the tolerance (in percent of the setpoint) within which the valves must begin to lift when calibrated and/or tested. The specified tolerance of 1% of the setpoint, has proven to be difficult to meet when the valves are tested. Therefore, Ceco has requested that Westinghouse perform an evaluation to support a relaxation in MSSV setpoint tolerances from 1% to 3% as defined in Technical Specification Section 3/4.7. This safety evaluation will address the effects of the 3% tolerance on FSAR Accident analyses (non-LOCA, LOCA, SGTR), the primary component design transients, and the plant Overpressure Protection Report. The. impact on the Main Steam System and the MSSVs is not within Westinghouse scope of supply and is not addressed in this evaluation.

During normal surveillance, if the valves are found to be within 3%,

they will be within the bases of the accident analyses. However, as required per Reference 4, it is strongly recommended that the valves be reset to the specified design tolerance ( 1%) to prevent future accumulation of drift beyond 3%. Resetting of the valves if the 1%

tolerance is exceeded is consistent with the existing Technical Specification requirements and the recommended Technical Specification modifications provided in Appendix D. Thus, this evaluation permits a -

3% setpoint tolerance to address as-found conditions.

The operation of the MSSVs is governed by the ASME Code (Reference 2). The ASME Code requires that the valves lift within 1% of the specified setpoint (NB-7512.2). The code also states that the valves must attain rated lift (i.e., full flow) within 3% of the specified setpoint (NF-7512.1). Thir evaluation will form the basis for taking exception to the ASME Code with respect to the lift setpoint tolerances. As defined in NB-7512.2, exceptions can be made to the code providing the effects are accounted for in the accident analyses, specifically, the Overpressure Protection Report (Reference 3).

2.0 LICENSING BASIS Title 10 of the Code of Federal Regulations, Section 50.59 (10 CFR 50.59) allows the holder of a license authorizing operation of a nuclear power facility the capacity to initiate certain changes, tests and experiments not described in the Final Safety Analysis Report (FSAR). Prior Nuclear Regulatory Commission (NRC) approval is not required to implement the modification provided that the proposed change, test or experiment does not involve an unreviewed safety question or result in a change to the plant technical specifications incorporated in the license. While the proposed change to the MSSV 3

lift setpoint tolerances involves a change to'the Byron and Braidwood technical specificatiens and requires a licensing amendment request, this evaluation will be performed using the mdthod outlined under 10CFR50.59 to provide the bases for the determination that the proposed change does not involve an unreviewed safety question. In i addition,' an~ evaluation will demonstrate that the proposed change does not represent a significant hazards consideration, as required by-10CFR50.91 (a) (1) and will address the three test factors required by

, 10CFR50.92 (c).

i 3.0 EVALUATIONS

! The results of the various evaluations from the Nuclear Safety related j disciplines within Westinghouse scope are discussed in the following

sections.

! 3.1 Non-LOCA Evaluation l 3.1.1 AT Protection l

! The increase in the MSSV lift setpoint tolerance has the potential to

impact the Overtemperature AT and Overpower AT setpoint

! equations. Referring to UFSAR Figure.15.0-1, increasing the point at

which the MSSVs lift will lower the steam generator safety valve l line. If the current OTAT setpoint coefficients (K1 through K3) 4 result in protection lines that just bound the thennal core limits, it

is possible that by lowering the SG safety valve line to the right, a portion of the core limits will be uncovered.

! In order to evaluate the effects of the increase in the setpoint i tolerance, the Overtemperature AT and Overpower AT setpoint

, equations (K1 through K6) were examined to determine if the equations

. remained valid assuming that all 20 MSSVs opened with a +3%

tolerance. The results of that evaluation showed that there was .

I sufficient margin in the generation of the current setpoint equations to offset the lowering of the SG safety valve line. The results of this calculation are presented as Figure 1.

3.1.2 DNB Events The transients identified in Table 1 are analyzed in the Byron /Braidwood UFSAR to demonstrate that the DNB design basis is satisfied. With one exception, these events are a) of such a short duration that they do not result in the actuation of the MSSVs, b) core-related analyses that focus on the active fuel region only, or c) cooldown events which result in a decrease in secondary steam pressure. The single exception is the loss of external load / turbine trip event which is addressed explicitly in Section 3.1.7 of this evaluation. Thus, based on the above, these non-LOCA DN8 transients are not adversely impacted by the proposed change, and the results and conclusions presented in the UFSAR remain valid.

4

TABLE 1 -

DNB DESIGN BASIS TRANSIENTS

. --fYEHI UFSAR Section Feedwater System Malfunction: 15.1.1 Reduction in Temperature Feedwater System Malfunction: 15.1.2 Increase in Feedwater Flow Excessive Increase in Secondary Steam Flow 15.1.3 Inadvertent Opening of a SG Relief 15.1.4 or Safety Valve l

Steam System Piping Failure 15.1.5  !

(Double-Ended Rupture - Core Response)

)

Partial Loss of Forced Reactor Coolant Flow 15.3.1 Complete Loss of Forced R5,ctor Coolant Flow 15.3.2 Reactor Coolant Pump Shaft Seizure 15.3.3 (DNB & Overpressurization Concerns)

Reactor Coolant Pump Shaft Break 15.3.4 (DNB & Overpressurization Concerns)

Uncontrolled RCCA Bank Withdrawal 15.4.1 From a Suberitical Condition Uncontrolled RCCA Bank Withdrawal 15.4.2 at Power RCCA Misalignment 15.4.3 Inadvertent Operation of the ECCS 15.5.1 Inadvertent Opening of a 15.6.1 Pressurizer Safety or iAelief Valve Startup of an Inactive Reactor Coolant Pump 15.4.4 CVCS Malfunction (Boron Dilution) 15.4.6 5

-_ . - . . - - y

3.1*.3 Dilution Events The following dilution events are analyzed to demonstrate that the operators (or the automatic mitigation circuitry) have sufficient time to respond pr~ior to reactor criticality once an alarm is generated.

The secondary system is not modeled in the analysis of these events, and thus, changes.to the MSSVs have no impact on these events.

Therefore, the results and conclusions presented in the UFSAR remain valid.

DILUTION EVENTS UFSAR Section Startup of an Inactive Reactor 15.4.4 Coolant Pump CVCS Malfunction (Boron Diletion) 15.4.6 3.1.4 Steamline Break Mass & Energy Releases For the steamline break mass and energy releases, the steam release calculations are insensitive to the changes in the MSSV lift setpoints since the vast majority of these calculations result in depressurizations of the secondary side such that the MSSVs are not actuated. For the smaller break cases that might result in a heatup, based on the existing analyses one MSSV per steam generator is sufficient to provide adequate heat removal following reactor trip and is bounded by the MSSV assumption used in the current non-LOCA accident analyses. Thus, secondary pressures will be no greater than those presently calculated.

EXEHI UFSAR Section Steamline Rupture Mass & Energy Releases 6.2.1.4 Inside Containment .

Steamline Rupture Mass & Energy Releases WCAP-10961-P-A Dutside Containment for Equipment Environmental Qualification 3.1.5 Long-Term Heat Removal Events The only non-LOCA transients remaining are the long-term heatup events. The long-term heat removal events are analyzed to detenmine if the auxiliary feedwater (AFW) heat removal capability is sufficient to ensure that the peak RCS and secondary pressures do not exceed allowable limits, the pressurizer does not fill (LONF/LOACP), and the core remains covered and in a coolable geometry (FLB). These transients are listed below.

E11H1 UFSAR Section Loss of Non-Emergency AC Power 15.2.6 to Plant Auxiliaries (LOACP) 6

Loss of Normal Feedwater (LONF) 15.2.7

Feedwater System Pipe Break (FLB) 15.2.8 These transients are impacted by the increase in the MSSV lift i

setpoint tolerance because the calculations detemining the amount of AFW flow available must assume a maximum given steam generator  ;

, backpressure in order to determine the amount of AFW that can be l delivered. As the steam generator backpressure increeses, the amount 1

' of AFW delivered will be reduced. For the loss of non-emergency AC power and the loss of normal feedwater events, flow control valves in j

, the AFW lines, designed to limit flow to a preset value, :re assumed 1 to operate since they conservatively minimize the amount of AFW available for cooling. These transients assume an AFW flow rate of j 153 gpm per steam generator. If the valves were inoperable or failed during operation, they weald do so in the open position resulting in i

' higher AFW flow rates. The valves will function such that the 153 gpm accident analysis assumption will be met independent of the increase p in the generator backpressure.

4 l

i The feedline break event results in a faulted steam generator that depressurizes to atmospheric pressure. As a result, the AFW flow i control valves are assumed to fail, minimizing the amount of AFW I

available for long-term cooling. This assumption results in the AFW flow being preferentially fed to the faulted steam generator where it

is lost out the break. In order to ensure that some amount of AFW is

supplied to the remaining intact steam generators, passive orifice

plates, installed in each of the AFW lines, are used to limit the flow I to the faulted loop. Since there is no method available to throttle l AFW flow, the overall flow provided to the intact steam generators

during a feedline break event will be reduced as the backpressure increases. Therefore, the effects of the MSSV setpoint tolerance relaxation on AFW performance during a feedline break accident must be

considered.

i l A calculation was performed to determine the maximum steam pressure

inside an intact steam generator during the long-term cooling portion of the transient (i.e., after steamline isolation occurs). The

) results showed that the maximum steam pressure at Byron and Braidwood

is 1250 psia. Note that this value bounds both cases with and without 4 offsite power available. Based on subsequent calculations, it was i determined that the resultant AFW flow (458 gpm to the three intact steam generators) will remain greater than that currently assumed in

the licensing-basis feedline break analysis (420 gpe). Therefore, the j results and conclusions presented in the UFSAR (15.2.8) remain valid.

The final concern is the potential for steam generator i overpressurization following reactor trip for the other long-term heatup events. Based on the existing UFSAR loss of non-emergency AC

, power and loss of normal feedwater analyses, long-tem cooling j requires a maximum of 1-3% of nominal plant steam flow from each steam j generator or a plant total of 4-12% of nominal steam flow (depending i on the transient). In order to pass the required flow, the two lowest l

set MSSVs would be required to lift. With a 3% lift tolerance, this l

f 7 i

~

condition could result in full open pressures for the tt:o valves of 1249.5 and 1265.3 psia, respectively. The re]ief capacity of the first 2 MSSVs full open on each steam generator bounds 12% nom'inal steam flow. Thus, the steam flow requirement would be satisfied and resultant steam pressure of -1265 psia would not exceed 110% of the secondarf'de' sign pressure (1320 psia). As discussed above, the maximum expected pressure for a feedline break event is 1250 psia which is also less than the limit. Therefore, the proposed change does not adversely impact the long-term cooling overpressurization requirements.

Thus, based on the discussions presented above, only one UFSAR transient is impacted such that a new analysis must be performed in order to address the effects of the MSS'! lift setpoint tolerance increase from 1% to 3%. This event is the loss of external load / turbine trip accident. For the remaining transients, the results and conclusions presented in the Byron /Braidwood UFSAR remain valid.

3.1.6 -3% Tolerance Secondary steam releases are generated for the offsite dose calculations for the following non-LOCA transients: the steam system piping failure (UFSAR Table 15.1-3), the loss of external load (UFSAR Table 15.2-4), and the RCP shaft seizure (locked rotor - UFSAR Table 15.3-3). The methodology used to calculate these masses is based on determining the amount of secondary side inventory raquired to cool down the RCS. During the first two hours (0-2 hours), the operators are assumed to lower the RCS average temperature to no-load conditions (557'F) by bleeding steam. Over the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (2-8 hobrs), the operators will cool the plant down such that Mode 4 operation (hot shutdown) can be entered.

The existing steam release calculations for the 0-2 hour period used enthalpies corresponding to saturated conditions at both the nominal

( full power RCS average temperature and the no-load temperature -

(588'F and 557'F, respectively). Thus, as long as the increased lift setpoint tolerance (-3%) does not result in the MSSVs remaining open at a saturation temperature outside of the range identified above, the existing mass releases remain valid.

The existing mass release calculations were performed using the temperatures previously identified (588'F and 557'F). Per the Byron /Braidwood Technical Specifications, the lowest set MSSV on each steam generator will open at 1190 psia (1175 psig) not including any tolerance. Based on the ASME Steam Tables (Reference 6) at saturated conditions, 557'F corresponds to 1106.4 psia and represents the lowest steam pressure considered in the mass calculations. Thus, the existing releases include a ressat pressure equal to 7% below the lowest Technical Specification lift setpoint. As long as the valves continue to resent within this pressure range, the current mass releases remain valid.

8 l .

i

1 3.T.7 Analysis Summary

3.1.7.1 Loss of External Load / Turbine Trip The loss 'df external load / turbine trip event is presented in Section

! 15.2.3 of the Byron /Braidwood UFSAR. This transient is caused by a turbine-generator trip which results in the innediate termination of steam flow. Since no credit is taken for a direct reactor trip on turbine trip, primary and secondary pressure and temperature will

begin to increase, actuating the pressurizer and steam generator 4

safety valves. The reactor will eventually be tripped by one of the

)

i other reactor protection system (RPS) functions; specifically, i

overtemperature AT, high pressurizer pressure, or low-low steam )

generator water level.

1 The turbine trip event is the limiting non-LOCA event for potential i overpressurization, i.e., this transient forms the design basis for I i the primary and secondary safety valves. Since the MSSVs will now j potentially be opening at a higher pressure due to the increase in i the lift setpoint tolerance, it is necessary to analyze this j transient in order t.o demonstrate that all the applicable acceptance i criteria are satir,fied. A turbine trip is classified as an ANS condition II event, a fault of moderate frequency. As such, the appropriate acceptance criteria are DNBR, peak primary pressure, and peak secondary pressure. The transient is described in greater

detail in the UFSAR.

The turbine trip event is analyzed using a modified version of the LOFTRAN digital computer code (Reference 7). The program simulates neutron kinetics, reactor coolant system, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generators, and main steam safety valves. With the modified code, the MSSVs are explicitly modeled as a bank of 5 valves on each steam generator with staggered lift setpoints. Since higher steam pressures are .

conservative for this event, no blowdown cr hysteresis behavior was assumed.

Consistent with the existing UFSAR analysis, the following assumptions were used in this analysis:

a. Initial power, temperature, and pressure were at their nominal values consistent with ITDP methodology (WCAP-8567).

b. Turbine trip was analyzed with both minimum and maximum reactivity feedback corresponding to beginning-of-life and end-of-life conditions, respectively,

c. Turbine trip was analyzed both with and without pressurizer pressure control. The PORVs and sprays were assumed operable in the cases with pressure control. The cases with pressure control minimize the increase in primary pressure which is conservative for the DNBR transient. The cases without pressure control maximize the increase in pressure which is conservative for the RCS overpressurization criterion.

9

i ,

d. The stean generator PORV and steam dump.yalves were not assumed operable. This assumption maximizes secondary pressure,

e. ' Main feedwater flow was assumed to be lost coincident with the turbine trip. This assumption maximizes the heatup effects.

1

f. Only the overtemperature AT, high pressurizer pressure, and

low-low steam generator water level reactor trips were assumed operable for the purposes of this analysis.

3

g. The MSSVs were assumed to lift 3% above the Technical Specification setpoints and were assumed to be full open 5% abose

, the setpoints. This is consistent with the 2% difference betwe1n lift and rated flow currently included in the code.

i

h. An individual MSSV was assumed to have a full flow capacity of 4

249 lbm/sec.

! 3.1.7.2 Analysis Results Four cases were analyzed: a) mini. mum feedback without pressure control, b) maximum feedback without pressure control, c) maximum 4

feedback with pressure control, and d) minimum feedback with i

pressure control. The calculated sequence of events for the four cases is presented in Table 2.

Case A:

Figures 2 through 4 show the transient response for the turbine trip event under BOL conditions without pressure control. The reactor is tripped on high pressurizer pressure. The neutron flux remains essentially constant at full power until the reactor is tripped, and the DNBR remains above the initial value for the duration of the transient. The pressurizer safety valves are actuated and maintain -

primary pressure below 110% of the design value. The main steam safety valves are also actuated and maintain secondary pressure below 110% of the design value.

Case B:

Figures 5 through 7 show the transient response for the turbine trip l event under EOL conditions without oressure control. The reactor is tripped on high pressurizer pressure. The DNBR increases throughout the transient and never drops below the initial value. The pressurizer safety valves are actuated and maintain primary pressure l below 110% of the design value. The main steam safety valves are also actuated and maintain secondary pressure below 110% of the design value.

Case C:

Figures 8 through 10 show the transient response for the turbine trip event under EOL conditions with pressure control. The reactor is tripped on overtemperature AT. The DNBR increases throughout the transient and never drops below the initial value. The 10

t i

pressurizer relief valves and sprays aaintain primary pressure below 1

110% of the design value. The cain steaa safety valves are also I

actuated and maintain secondary pressure b410w 110% of the design value.

Case D:

Figures 11 through 13 show the transient response for the turbine

trip event under BOL conditions with pressure control. The reactor 4 is tripped on overtemperature AT. The neutron flux remains 4 essentially constant at full power until the reactor is tripped, and i although the DNBR value decreases below the initial value, it remains well above the limit throughout the entire transient. The pressurizer relief valves and sprays maintain primary pressure below

110% of the design value. The main steam safety valves are also l actuated and maintain secondary pressure below 110% of the design i

value.

3.1.7.3 Analysis Conclusions Based on the results of these turbine trip analyses with a +3%

tolerance on the MSSV lift setpoints, all of the applicable

acceptance criteria are met. The minimum DNBR for each case is j greater than the limit value. The peak primary and secondary i pressures remain below 110% of design at all times.

l .

t i

b i

i i

i 11 i

TABLE 2 o.

I ._ -- TURBINE TRIP SEQUENCE OF EVENTS 1

TIME ACCIDENT lylEI M Without pressurizer Turbine trip, loss of main 0.0 control (minimum feedwater flow '

reactivity feedback)

High pressurizer pressure 4.3 reactor trip setpoint reached Rods begin to drop 6.3 Initiation of steam release 6.5 from the MSSVs Peak pressurizer pressure 7.5 occurs Minimum DNBR occurs (1)

Without pressurizer Turbine trip, loss of main 0.0 control (maximum feedwater flow reactivity feedback)

High pressurizer pressure 4.3 reactor trip setpoint -

reached Rods begin to drop 6.3 Initiation of steam release 6.5 from the MSSVs Peak pressurizer pressure 7.0 occurs Minimum DNBR occurs (1)

(1) DNBR does not decrease below its initial value.

12

TABLE 2 *.

(continued)

~~~~~

TURBINE TRIP SEQUENCE OF EVENTS TIME ACCIDENT M!il 1.11C.1 With pressurizer Turbine trip, loss of main 0.0 control (maximum feedwater flow reactivity feedback)

Initiation of steam release 6.5 from the MSSVs Overtemperature AT 7.4 reactor trip setpoint reached Peak pressurizer pressure 7.5 occurs Rods begin to drop 9.4 Minimum DNBR occurs , (1)

With pressurizer Turbine trip, loss of main 0.0 control (minimum feedwater flow reactivity feedback)

Initiation of steam release 6.5

from the MSSVs Overtemperature AT 6.9 reactor trip setpoint reached Rods begin to drop 8.9 Minimum DNBR occurs 10.0

) Peak pressurizer pressure 10.5 occurs 4

(1) DNBR does not decrease below its initial value.

d 13

3,1.8 Overpressure Protection Report The Overpressure Protection Report (Reference 3) is published to demonstrate that the limiting ANS Condition II pressurization transient..(. loss of load / turbine trip) does not result in primary and secondary pressures in excess of 110% of the design values. The Overpressure Protection Report has been reviewed as part of this safety evaluation. In order to determine the effects of the increases in the lift setpoint tolerances, the loss of load / turbine trip transient presented in the Overpressure Protection Report was analyzed. The new analysis was performed consistent with the existing report with the exception of the explicit MSSV modeling described in the LOFTRAN description above. The results of this analysis demonstrated that the peak RCS pressure, assumed to be at the outlet of the reactor coolant pumps, was below the limit value (2750 psia).

With respect to the secondary steam system, the transient analysis resulted in approximately 60% of the total MSSV relief capacity being used. It also showed that the maximum secondary steam pressure was less than the limit (1320 psia). Thus, the conclusions presented in the Overpressure Protection Report remain valid. Changes to this report are included in this report.

3.1.9 Non-LOCA Conclusions The effects of increasing the as-found lift setpoint tolerance on the main steam safety valve have been examined, and it has been

. deterwined that, with one exception, the current accident analyses as presented in the UFSAR remain valid. The loss of load / turbine trip event was analyzed in order to quantify the impact of the setpoint tolerance relaxation. As previously demonstrated in this evaluation, all applicable acceptance criteria for this event have been satisfied and the conclusions presented in the UFSAR are still valid. Thus, the proposed Technical Specification change does not constitute an -

unreviewed safety question, and the non-LOCA accident analyses, as presented in the report, support the proposed change.

Changes to the UFSAR and the Overpressure Protection Report are included in this safety evaluation as appendices.

3.2 LOCA and LOCA Related Evaluations T % effects of increased tolerances for the Main Steam Safety Valve (MSSV) setpoints on the LOCA safety analyses has been previously perfonned for VANTAGE 5 fuel. The current Technical Specification setpoints with rated flow is given below for easy reference. The effect of either increasing or decreasing the setpoint by 3%,

depending upon the direction of conservatism, has been evaluated for the LOCA analyses.

MSSLNUMBER T/S SETPOINT RATED FLOW ACTUAL FLOW MS017A,B,C,D 1190 (PSIA) 841,427 934,918 14

MS016A,B,C,D 1205 (PSIA) 852,039., 946,710 MS015A,B,C,0 1220 (PSIA) 862,652 958,502 MS014A,B,C,0 1235 (PSIA) 873,265 970,294 MS013A,B,C,D. 1250 (PSIA) 883,878 982,087 Rated flow should be used for heat-up accidents and actual flow ,

should be used for cooldown accidents. The following presents the ~

! effect of the proposed setpoint revision from 1% to 13% on the LOCA-related analyses.

3.2.1 Large Break LOCA (FSAR Chapter 15.6.5)

Calculations performed to determine the response to a hypothetical i large break LOCA do not model the MSSVs, since a large break LOCA is characterized by a rapid depressurization of the reactor coolant system primary below the pressure of the steam generator secondaries. Thus, the calculated consequences of a large break LOCA are not dependent upon assumptions of MSSV performance. Therefore, the large break LOCA analysis results are not adversely affected by the proposed revised MSSV setpoint tolerances.

3.2.2 Small Break LOCA (FSAR Chapter 15.6.5)

Small Break LOCAs are dependent upon heat transfer from the Reactor Coolant System (RCS) primary to the steam generator secondary in order to limit the consequences of the accident. A period exists

,~ when the RCS primary pressure hangs above the steam generator secondary pressure and excess decay heat is transferred to the steam generators. Since a loss of offsite power is assumed to occur coincident with the small break LOCA, the steam dump system and power operated relief valves are assumed to be inactive. Thus, steam -

relief from the steam generator secondaries takes place through the MSSVs.

l The small break LOCA analyses presented in Appendix C of the Byron /Braidwood Stations Units 1 and 2 VANTAGE 5 Reload Transition Safety Report were performed using a 3% higher safety valve setpoint pressure. The standard 3% accumulation between valve actuation and i '

full flow was also accounted for in the' analyses. These analyses

' calculated peak cladding temperatures well below the allowed 2200 0F limit as specified in 10CFR50.46. demonstrating that the proposed change to the MSSV technical specification can be accommodated for small break LOCAs.

A reduction in the MSSV setpoint tolerance would act to lower the i secondary pressure. Since the RCS pressure is controlled by the steam generator secondary pressure through the MSSVs, a decrease in j secondary pressure would also result in a lower RCS pressure. A

lower RCS pressure would result in more safety injection flow I delivered to the RCS. As such, the -3% MSSV setpoint tolerance would i

provide increased safety injection water to the RCS, which would act i to reduce the calculated peak clad temperature. Therefore, a -3%

4 MSSV setpoint tolerance would not adversely affect the small break j LOCA analysis results.

l l 15

While the PCT has increased due to the revised +3% MSSV setpoint tolerance, the calculated PCT remains below'22000F. Therefore, it is concluded that the increase in the MSSV setpoint tolerances limit to plus or,minus 3 percent does not adversely affect the small break LOCA analysis results.

3.2.3 LOCA Blowdown Reactor Vessel and RCS Loop Forces (FSAR Chapter 3.9)

The licensing basis LOCA hydraulic forces analysis results found in l the FSAR calculate that the peak leads occur within the first 500 milliseconds of the transient. This occurrence is well before any

, automatically operated safety feature has responded to the LOCA and

! before steam generator pressures could reach the set-pressures of the MSSVs. Therefore, changes in the MSSV Technical Specification set-pressures do not change the calculated consequences appearing in '

! the FSAR.

l 3.2.4 LOCA Mass and Energy Releases for Containment Integrity Analyses (FSAR Chapter 6.2)

There is no effect due to increasing the tolerance of the steam generator Main Steam Safety Valve (MSSV) setpoints from 1% to 3% on short or long tern LOCA mass and energy release and the resulting i

containment integrity response. Since a large break LOCA rapidly decreases the RCS pressure below that of the steam generator secondary pressure, the philosophy for long term LOCA considerations is to release all steam generator metal energy and primary coolant to containment. Therefore, only secondary to primary heat transfer is important in determining the amount of energy released to containment. Benefits from any mechanisms, such as MSSVs, that may.

possibly reduce the amount of available steam generator stored ~ energy are small. Therefore, MSSVs are not modeled in the analysis perforced to calculate the consequences for the long ters design basis LOCA -

event.

The short term mass and energy release calculation is teminated after a few seconds. This time duration is so short as to preclude any appreciable effect due to either secondary to primary heat transfer or potential MSSV actuation.

3.2.5 Steam Generator Tube Rupture (FSAR Chapter 15.6.3)

For the steam generator tube rupture (SGTR) event, the FSAR analysis was performed to evaluate the radiological consequences. The major factors that affect the radiological doses are the amount of primary coolant transferred to the secondary side of the ruptured steam generator through the ruptured tube, the steam released from the ruptured steam generator to the atmosphere and the amount of radioactivity in the reactor coolant. The impact on these parameters of changing the main steam safety valve setpoint tolerance from 1% to 3% has been determined.

For the FSAR SGTR analysis, the loss of inventory due to the tube rupture results in a decrease in pressurizer pressure. Reactor trip l

16

- - . - - - . - _ - - . . - ~ . - . - . . . .- . . _ _ . ~ . - - - . - . - . . -

$) plus SI actuation trere assumed to occur on lo'.s pressurizer pressure.

l A loss of offsite power was also assumed to occur at the time of 1

reactor trip, thus the steam duzp system was.' assumed to be

unavailable. The energy transfer from the primary system following

reactor and turbine trip causes the secondary side pressure to l J increase rapidly after reactor trip until the steam generator power  !

i operated relief valves (PORVs) and/or safety valves lift to dissipate j i the energy. For the SGTR analysis, it was assumed that the secondary '

i pressure is maintained at the lowest secondary safety valve setpoint following reactor trip. After reactor trip and SI initiation, the RCS pressure was assumed to reach equilibrium at the point where the incoming SI flowrate equals the outgoing break flowrate, and the

! equilibrium pressure and break flowrate were assumed to persist until l 30 minutes after the accident. A change in the main steam safety i valve setpoint tolerance to -3% will result in the secondary pressure i being maintained at a lower pressure during this 30 minute period, I thereby increasing the primary to secondary pressure differential.

l This will result in an increase to the primary to secondary break flow j and the atmospheric steam release via the ruptured steam generator.

i j - An evaluation was performed to detemine the effect of decreasing' the i

safety valve setpoint by -3% with respect the SGTR analysis in the i FSAR. It is noted that this evaluation was performed in conjunction

} with the other changes associated with the VANTAGE-5 fuel upgrade, j specifically 15% steam generator tube plugging and a hot leg temperature range of 618.40 F to 600.00F. The results of the

evaluation indicated that the break flow increases slightly but is i still less than the conservative value reported in the FSAR for the SGTR event by approximately 2%. It is noted that the reactor coolant i activity assumed for the SGTR analysis in the FSAR is based on 1% fuel defects and is assumed to be independent of the transient conditions.

l Therefore this assumption would not be affected by the aforementioned j changes.

! A radiological analysis using the revised mass releases was completed ,

! which indicates that the slight increase in the steam release is

offset by the margin in the primary to secondary break flow (which j exists in the FSAR report), such that the offsite radiation doses are

, less than the results reported in the FSAR. Therefore, it is i concluded that a change in the MSSV setpoint tolerance from i1% to 3%

j will not increase the consequences of a SGTR as reported in the FSAR.

3 l 3.2.6 Hot Leg Switchover of the ECCS to Prevent Potential Boron

Precipitation (FSAR Chapter 6.3.2.5) 1 The calculations performed to determine the time (post-LOCA) at which i the boron concentration in the reactor vessel would exceed the i solubility limit do not require modeling of the main steam safety

valves. However, an evaluation is required to assure that adequate

- ECCS flow is provided to prevent boron precipitation following the j switchover to hot leg recirculation. The minimum time for hot leg

! switchover for the Byron /Braidwood Stations was calculated to be 18 1 hours based on large break LOCA assumptions. The calculated core i

4 l 17

_ ._ _ . __ _ _ . _ _ . . _ . _ . _ _ _ _ _ _ _ - _ _ ~ . _ _ _ . . _ - - _ _ _ _

i boil-off rate at 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> teculd be approxicately 20 lbm/sec. The ainicum ECCS flow required for delivery to the hot legs following

, switchover is 1.5 times the boil-off rate for's large break LOCA or approximately 30 lbm/sec. The RCS pressure for a small break LOCA at

the hot leg switchover time of 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> can conceivably be as high as the highest" steam generator safety valve setpoint (approximately 1250 psia plus 3%). Conditions for a small break LOCA differ significantly from those for a 1.arge break LOCA such that the requirements to 3 prevent boron precipitation are much less restrictive than those for a large break LOCA. Thus, under small break LOCA conditions, ECCS flow

to both the hot and cold legs can be considered in satisfying the

! boil-off requirement. Thus the charging and safety injection pumps

! must meet or exceed 30 lbs/sec at 1288 psia in order to satisfy the boil-off requirement for a small break LOCA. A review of the ECCS

< shows that the safety injection pumps, when aligned in the hot leg i recirculation mode, can deliver more than the required 30 lbm/sec at i an RCS pressure of 1288 psia. Thus, the proposed change to the MSSV .

, Technical. Specification setpoint pressure tolerance from 1% to 3% ,

! will not alter the results or conclusions appearing in the FSAR '

l regarding the switchover of the ECCS to hot leg recirculation.

3.2.7 Post-LOCA Longterm Core Cooling (FSAR Chapter 15.6.5) 4 l Since the post-LOCA suberiticality is based on large break I l' requirements, deviations in MSSV set-pressures do not effect the borun concentration in the containment sump post-LOCA. Thus, the proposed change to the MSSV Technical Specification setpoint pressure tolerance from 1% to 3% will not alter the results or conclusions regarding the ability to keep the reactor cores suberitical on the boron provided by the ECCS.

3.2.8 LOCA Conclusions ,

The effect of a increase in the allowable Main Steam Safety Valve set pressure tolerance from 1% to 3% on the FSAR LOCA analysis has been '

evaluated. In each case the applicable regulatory or design limit was satisfied. Specific analyses were performed for small break LOCA assuming the current MSSV Technical Specification set pressures plus the proposed additional 3% uncertainty. The calculated peak cladding temperatures were well below the 10 CFR 50.46 22000F limit.

3.3 Containment Intearity Evaluation Neither the mass and energy release to the containment following a postulated loss of coolant accident (LOCA), nor the containment response following the LOCA analysis, credit the MSSV in mitigating the consequences of an accident. Therefore, changing the MSSV lift setpoint tolerances would have no impact on the containment integrity analysis.

In addition, based on the conclusion of the transient analysis, the change to the MSSV tolerance will not affect the calculated steamline break mass and energy releases inside containment. Consequently, the main steam line break containment integrity analysis is not impact by the change to the MSSV setpoint tolerances.

18

i _

3.4 E0P Evaluation In the Emergency Operating Procedures (EOPs), the MSSV setpoint pressures are used to determire when to trip the reactor coolant pumps

! (RCPs). 'The-determination is conservative, taking into account

, instrument uncertainties. The conservatism, along with the small l

difference between the MSSV pressure used to determine the RCP trip setpoint for the E0Ps and the in-plant first lift pressures of less than 0 is area.

l The MSSV pressures are also used in the E0Ps on the heat sink status l

t tree in determining which heat sink E0P is appropriate for implementation. These pressures are only involved in optional or yellow l paths on the heat sink status tree. This means that the plant condition

! is such that the operator is not required to perform the heat sink E0Ps

! called for by these yellow paths. Consequently, an inappropriate j transition to these procedures would not cause the operator to forego an j action required to maintain the plant in a safe condition. Thus, the

variations found between the E0P MSSV setpoints and the MSSV in-plant l lift pressures have negligible impact on the E0Ps in this area. If the set pressures are within 5%, use of these procedures will ensure that l the secondary pressure remains within acceptable limits.

I 4.0 DETERMINATION OF UNREVIEWED SAFETY OUESTION i

~

1. Will the probability of an accident previously evaluated in the SAR be increased?

The 3% tolerance on the MSSV setpoint does not increase the probability

of an accident previously evaluated in the FSAR. There are no hardware j modifications to the valves. Therefore, there is not an increase in the -

spurious opening of a MSSV. The MSSVs are actuated after an accident is j initiated to protect the secondary systems from overpretsurization.

j Sufficient margin exists between the normal steam system operating i pressure and the valve setpoints with the increased tolerance to 4

preclude an increase in the prebability of actuating the valves.

j Therefore, the probability of an accident previously evaluated in the

FSAR would not be increased as a result of increasing the MSSV lift 1 setpoint tolerance by 3% above or below the current Technical i Specification value.

2. Will the consequences of an accident previously evaluated in the SAR be increased?

! All of the applicable LOCA and non-LOCA design basis acceptance criteria l

remain valid both for the transients evaluated and the single event analyzed. Additionally, no new limiting single failure is introduced by a the proposed change. The DNBR and PCT values remain within the i specified limits of the licensing basis. Although increasing the valve i setpoint will increase the steam release from the ruptured steam j generator above the FSAR value by approximately 2%, the SGTR analysis i

4 19 l

indicates that the calculated break flow is still less than the value l reported in the FSAR. Therefore, the radiological analysis indicates that the slight increase in the steam release is offset by the decrease

in the break flow such that the offsite radiation doses are less than -

those reported in the FSAR. The evaluation also concluded that tha i existing mass releases used in the offsite dose calculations for the i remaining transients (i.e., steamline break, rod ejection) are still 1 applicable. Therefore, based on the above, there is no increase in the dose releases.

l 3. May the possibility of an accident which is different than any already

evaluated in the SAR be created?

TM 3% tolerance on the MSSV setpoint does not create the possibility  ;

of an accident which is different than any already evaluated in the '

FSAR. Increasing the lift setpoint tolerance on the MSSVs does not introduce a new accident initiator mechanism. No new failure modes have

{ been defined for any system or component important to safety nor has any J

! new limiting single failure been identified. No accident will be

created that will increase the challenge to the MSSVs and result in 1 increased actuation of the valves. Therefore, the possibility of an

! accident different than any already evaluated is not created.

i i

I

4. Will the probability of a malfunction of equipment important to safety

previously evaluated in the SAR be increased?

! Although the proposed change takes place in equipment utilized to prevent overpressurization on the secondary side and to provide an

, additional heat removal path, increasing the as-found lift setpoint

tolerance on the MSSVs will not adversely affect the operation of the j reactor protection system, any of the protection setpoints, or any other

( device required for accident mitigation.

1

! 5. Will the cen:Hances of a malfunction of equipment important to safety  ;

j previously evaluated in the SAR be increased?

No, as discussed in the response to Questions 2, there is no possibility i

of increasing the dose releases as a result of increasing the as-found

lift setpoint tolerance on the MSSVs as defined in the attached safety l evaluation.

i

! 6. May the possibility of a malfunction of equipment important to safety j different than any already evaluated in the SAR be created?

j No, as discussed in Question 4, an increase in the as-found lift

setpoint tolerance on the MSSVs will not impact any other equipment j important to safety.

1 3

i -

l i

20

)

i

~ _ _ _ _ _ _ _. . - . _ _ _ _ _ _. _ _ _ _ _.._ -._ -__ _ _ _ _. _

7.

Will the cargin of safety as defined in the bases to any technical specification be reduced? ."

No, as discussed in the attached safety evaluation, the proposed increase.in the as-found MSSV lift setpoint tolerance will not invalidate the LOCA and non-LOCA conclusions presented in the UFSAR accident analyses. The new loss of load / turbine trip analysis concluded that all applicable acceptance criteria are still satisfied. For all the UFSAR non-LOCA transients, the DNB design basis, primary and secondary pressure limits, and dose release limits continue to be met.

Peak cladding temperatures remain well below the limits specified in 10CFR50.46. Thus, there is no reduction in the margin to safety.

5.0 CONCLUSION

S The proposed change to main steam safety valve lift setpoint tolerances from 1% to 3% has been evaluated by Westinghouse. The preceding analyses and evaluations have determined that operation with the MSSV setpoints within a 3% tolerance about the nominal values will have no adverse 'mpact upon the licensing basis analyses, as well as the steamline breax mass & energy release rates inside and outside of containment. In addition, it is on the MSSV setpoint does not adverseconcluded ly affect thethat the t3% tolerance overpower or overtemperature protection system. As a result, adequate protection to the core limit lines continues to exists. Therefore, all Itcensing basis criteria continue to be satisfied and the conclusions in the FSAR remain valid.

The recommended Technical Specification and FSAR changes, along with a no significant hazards evaluation, are presented as attachments to this evaluation.

Based on the information presented above, it can be concluded that the -

proposed increase of main steam safety valve lift setpoint tolerances from il% to 3% does not represent an unreviewed safety question per the definition and requirements defined in 10 CFR 50.59. ,

6.0 REFERENCES

1) Byron /Braidwood Technical Specifications through Amendments 37 and 23, respectively.

2) ANSI /ASME BPV-III-1-NB, "ASME Boiler and Pressure Vessel Code -

Section III Rules for Construction of Nuclear Power Plant Components,"

ASME, 1983.

3) CAW-3581/CBW-3009," Commonwealth Edison Company, Byron and Braidwood Stations - Units I and 2 Overpressure Protection Report," July 1981.

4) ANSI /ASME OM-1-1981, " Requirements for Inservice Performance Testing of Nuclear Power Plant Pressure Relief Devices," ASME, 1981 21

l

5) " Byron /Braidwood Stations Units 1 & 2 Updated. Final Safety Analysis Report (UFSAR), Docket Numbers 50-454, 455, 456, and 457, December 1989.

6) ASME Steam' Tables, Fifth Edition,1983. -

7) Burnett, T.W.T. , et al . , "LOFTRAN Code Description," WCAP-7907-P-A, June 1972.

1

8) Chelemer, H. et al. " Improved Thermal Design Procedure,"

WCAP-8567-P-A, February 1989. )

9) DiTommaso, S.D. et al.," Byron /Braidwood Thot Reduction Final Licensing Report," WCAP-11386-P, Revision 2, November 1987. 1 1

10) Butler, J.C. and D.S. Love,"Steamline Break Mass / Energy Releases for Equipment Environmental Qualification Outsids Containment,"

WCAP-10961-P, October 1985.

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• O* We APPENDIX A OVERPRESSURE PROTECTION REPORT

.- - OVERPRESSURE PROTECTION REPORT

, FOR BYRON /BRAIDWOOD NUCLEAR POWER PLANT UNITS 1 & 2 AS REQUIRED BY ASME BOILER AND PRESSURE VESSEL CODE SECTION III, ARTICLE NB-7300 JUNE 1981 Prepared by: R. J. Brown Contributions by: L. K. Casagrande

3. S. Tuoto Approved:

D. G. B{$aM

. Licence Application Analysis N '

jo Certified: y) . //j/_DJ)ditt/ / ffe Robert A. Wiesesann /ju raortssio$s

Professional Engineer-0087 . r.,

Commonwealth of Pennsylvan t _ ROBERT --m-,A. W1E' . '. I tucnutts ,y e M'111E W *fij

.s,... .

9356A:1 ,

. . . - - ~- .. - .. - - . . - -. .- - - . - . ..- - - . - -. _ . _ - . -

1 1

1,0 Purpose of Repert I l

Thir, report documents the overpressure protection provided for the  !

Reactor Coolant System (RCS) in accordance with the ASME Boiler and j Pressure Vessel Code,Section III, NB-7300. I 2.0 Description. of Overpressure Protection ,

2.1 Overpressure protection is provided for the RCS and its compo-nents to prevent a rise in pressure of more than 10% above the system :lesign pressure of 2485 psig, in accordance with NB-

,7400. This protection is afforded for the following events which envelope those credible events which could lead to over-pressure of the RCS if adequate over pressure protection were not provided.

1. Loss of Electrical Load and/or Turbine Trip

2. Uncontrolled Rod Withdravel at Power -

3. Loss of Reactor Coolant Flow

4. Loss of Normal Feedwater

5. Loss of Offsite Power to the Station Auxiliaries 2.2 The extent of the RCS is as defined in 10CFR50 and includes:

1. The reactor vessel including control rod drive mechanism l housings. '

~

2. The reactor coolant side of the steam generators.

3. Reactor coolant pumps.

4. A pressuriser attached to one of the reactor coolant loops.

5. Safety and relief valves.

6. The interconnecting piping, valves and fittings between the principal components listed above.

The piping, fittings and valves leading to connecting 7.

auxiliary or support systems up to and including the second isolation valve (from the high pressure side) on each line.

2.3 The pressuriser provides volume surge capacity and,is designed to mitigate pressure increases (as well as decreases) caused by load transients. A pressuriser spray system condenses steam at a rate sufficient to prevent the pressuriser pressure from reaching the setpoint of the power-operated relief valves 4

during a step reduction in power level equivalent to ten per-cent of full rated load.

9356A:1 *

(1) '

i  !

1 , ,

The spray nozzio is located in tho, cop hsad of the pressur-

{

i izer. Spray is initiated when the pressure controlled spray

demand signal is above a given setpoint. The spray rate I i .. increases proportionally with increasing compensated error i

signal until it reaches a maximum value. The compensated

! error signal is the output of a proportional plus integral  !

controller, the input to which is an error signal based on the difference between actual pressure and a reference pressure.

[ The pressurizar is equipped with 2 power-operated relief l valves which limit system pressure for a large power mismatch to avoid actuation of the fixed high pressure reactor trip. l

. The relief valves are operated automatically or by remote manual control. The operation of these valves also limits the i frequency of opening of the spring-loaded safety valves.

i Remotely operated stop valves are provided to isolate the i power-operated relief valves if excessive leakage occurs. The 1

relief valves are designed to limit the pressurizar pressure to a value below the high pressure trip setpoint for all j design' transients up to and including the design percentage step load decrease with steam dump but without reactor trip. j 4

Isolated output signals from the pressurizar pressure protec-i tion channels are used for pressure control. These are used to control pressurizer spray and power-operated relief valves in the event of increase in RCS pressure.

! i l In the event of unavailability of the pressurtzer spray or '

l power operated relief valves, and a complete loss of stean '

l flow to the turbine, protection of the RCS against overpres- i j -

sure is afforded by the pressurizar sa'Isty valves in conjune- )

{ tion with the steam generator safety valves and a reactor trip j initiated by the Reactor Protection System. -

l There are 3 safety valves with a minimum required capacity of j 420,000 lb/ hour for each valve at system design pressure plus j 3% allowance for accumulation. The pressuriser safety valves

! are totally enclosed pop-type, spring loaded, self-activated valves with back pressure compensation. The set pressure of the safety valves will be no greater than systen design pres-ou n of 2485 psig in accordance with section NB7511. The pressuriser safety valves and power operated relief valves

~

discharge to the pressurizer relief tank (PRT). Rupture disks

} are installed on the pressuriser relief tank to prevent PRT

! overpressurization.

t .

! Figure 1 shows a schematic arrangement of the pressure reliev-  !

j ing devices.  !

4 i

j 3.0 Sizing of Pressurizer Safety Valves i

3.1 The sizing of the pressuriser safety valves is based on analy- i i sis of a complete loss of steam flow to the turbine with the i

! reactor operating at 102% of Engineered Safeguards Design i Power. In this analysis, feedwater flow is also assumed to be i .

j 9356A: 1 -(2)

a icst, cnd no credit is taken for pparation of pressurizar power operated relief valves, pres'surizer level control sys-tea, pressurizer spray system rod control systes, steamdump

" ~system or steam line power ope, rated relief valves. The reac-tor is maintained at full power (no credit for reactor trip),

and steam relief through the steam generator safety valves is considered. The total pressuriser safety 5.1ve capacity is required to be pt least as large as the maximum surge rate into the pressuriser during this transient.

This sizing procedure results in a safety valve capacity well in excess of the capacity required to prevent exceeding 110%

of system design pressure for the erents listed in Section 2.1. The conservative nature of this sizing procedure is demonstrated in the following section.

3.2 Each of the overpressure transients listed in Section 2.1 has been analyzed and reported in the Final Safety Analysis Report. The analysis methods, computer codes, plant initial conditions and relevant assumptions are discussed in the FSAR for each transient.

Review of these transient's shows that the Turbine Trip results in the maximum systes pressure and the maximum safety valve relief requirements. This transient is presented in detail below.

For a turbine trip event, the reactor would be tripped directly (unless below approximately 10 percent power) from a signal derived from the turbine stop emergency trip fluid pressure and turbine stop valves. The-turbine stop valves close rapidly (typically 0.1 seconds) on loss of trip fluid pressure actuated by one of a number of possible turbine trip .

signals. This will cause a sudden reduction in steam flow, resulting in an increase in pressure and temperature in the steam generator shell. As a result, heat transfer rate in the steam generator is reduced, causing the reactor coolant tem-perature to rise, which in turn causes coolant expansion, pressuriser insurge, and RCS pressure rise.

The autcastic steam dump system would normally accoannodate the excess steam generation. Reactor coolant temperature and pressure do not significantly increase if the steam dump sys-tem and pressuriser pressure control system' are functioning properly. If the turbine condenser were not available, the excess steam generation would be dumped to the atmosphere and main feedwater flow would be lost. For this situation feed-water flow would be maintained by the Auxiliary Feedwater System to ensure adequate residual and decay heat removal capability. Should the steam dump system fail to operate, the steam generator safety valves may lift to provide pressure control.

9356A:1 -

(3)

l 9

In this . analysis, tha bahavior of the unit is evaluated for a comploto less of steam losd from IV2 parcent of full power without direct reactor trip; that is, the turbine is assumed to trip without actuating all the sensors for reactor trip on l

~~"the turbine stop valves. The assumption delays reactor trip l until conditions in the RCS result in a trip due to other  !

signals. Thus, the analysis assumes a worst transient. In addition, no cr, edit is taken for ste'sadump. Main feedwater flow is terminated at tha time of turbine trip, with no credit ,

taken for auxiliary feedwater to mitigate the consequences of )

the transient. l l

The turbine trip transients are analyzed by employing the detailed digital computer program LOFTRAN. The program simu-lates the neutron kinetics, RCS, pressurizer, pressurizer ,

relief and safety valves, pressuriser spray, steam generator, and steam generator safety valves. The program computes per-tinent plant variables including temperatures, pressures, and power level.

Major assumptions are summarized below:

a. Initial operating conditions The initial reactor power and RCS temperatures are assumed at their maximum values consiscent with the steady state full power operation including allowances for calibration and instrument errors. The initial RCS pressure is assumed at a minimum value consistent with the steady i state full power operation including allowances for cali-  !

bration and instrument errors. This results in the maxi-zum power dif ference for the load loss, and the minimum margin to core protection limits at the initiation of the ,

accident.

b. Moderator and Doppler coefficients of reactivity The analysis assumes both a least negative moderator coef-ficient and a least negative Doppler power coefficient, as this results in maximum pressure relieving requirements.

c. Reactor control From the standpoint of the maximum pressures attained it is conservative to assume that the reactor is in manual control. If the reactor were in automatic control, the control rod banks would move prior to trip and r' educe the severity of the transient.

t a

9356A: 1 (4)

.. d. Steca roleess No credit is taken for the operation of the steam dump

- - ~ ~ ~

system or steam generator power operated relief valves.

The steam generator pressure rises to the safety valveg setpoint where steam release through safety valves liatts

' secondar{ysteampressure::th: ::: :: int ::1;;.

4. le ss %.. llO */, .f %e, de.s/p va. ut. #

e. Pressuriser spray and power operated relief valves No credit is taken for the effect of pressuriser spray and power operated relief valves in reducing or limiting the coolant pressure. Safety valves are operable.

f. Feedwater flow Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No credit is taken for auxiliary feedvater flow since a stabilised plant condition will be reached before auxiliary feedwater initiation is normally assumed to occur; however, the auxiliary feedwater pumps would be expected to start on a trip of the main feedwater pumps. The auxiliary feedwater flow would remove core decay heat following plant s tabilization.

3 Ren64t* 4*ip gu Reactor trip is' actuated by the first Reactor Protection System trip setpoint reached with no credit taken for the direct reactor trip on the turbine trip. Trip signals are expected due to high pressuriser pressure, Overtemperature AT, high pressuriser water level, end low-low steam generator water level.

The results of the Turbine Trip transient are shown in Figures '

2 and 3. Tigure 2 shove the pressuriser pressure, the reactor coolant pump discharge pressure, which is the point of highest pressure in the RCS, and the pressuriser safety valve relief rate. Figure 3 shows steam generator shell side pressure, reactor coolant loop hot leg and cold leg temperature, and nuclear power. The reactor is tripped on a high pressuriser pressure signal for this transient. -

The results of this analysis show that the overpressure' pro-tection provided is sufficient to maintain peak RCS pressure below the code limit of 110% of system design pressure. The plot of pressuriser safety valve relief rate also shows that adequate overpressure protection for this limiting event could be provided by two of the three installed safety valves.

4.0 References

1. ASME Boiler and Pressure Vessel Code,Section III, Article NB 7000, 1971 Edition Winter 1972 Addenda.

9356A 1 *

(5)

,,= - , .-n.- .- - - . - - -

, 2. Topier.1 Report - Overpressure Protection for Wastinghouse Pressurizer Wate.- Reactors, WdAP 7769, Rev. 1, June 19 72.

__.3. Certified Safety Valve Capacity, Calculation No. CPA 44; FA-792, July 23, 1980, Corrected January 22, 1981.

4. CAE'0FA Loss of Load Accident (FSAR Am'endment), Calcula-tion No. CH-PP-80-94, September, 1979.

5. CAE FSAR Loss of Load / Turbine Trip Calculation No. CN-RPA-78-65, April, 1978.

6. CAE Underfrequency/ Loss of Flow / Locked Rotor Analysis for OFA-STAT CFB & Broken Pump Shaf t, Calculation No. CN-PP-80-129, Novecber , 1980.

7. CAE FSAR Loss of Flow & Locked Rotor; Broken Pump Shaf t; Underfrequency Analysis Calculation No. CN-RPA-78-49, Ma rch, 1978.

8. CAE OFA Amendment - Loss of Normal Feedwater and Station Blackout, Calculation No. CN-PP-80-115, November, 1980.

9. CAE FSAR Loss of Normal Feedwater and Station Blackout, CN-RPA-77-219, November, 1977.

10. CAE OFA FSAR Amendment - Rod Withdrawal s't Power Analysis, CN-PP-80-107, October, 1980.

11. CAE Rod Withdrawal at Power Calculation No. CN-RPA-78-36, Feb ruary, 1978.

12. CAE OFA Turbine Trip for Overpressure Protection Report, ,

Calculation No. CN-PP-81-2, January, 1981. ,

l 1

l 4

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4 9356A: 1 (6)

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Figure 1 Schematic Arrangement Of Pressure flelieving Device 5

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APPENDIX B UFSAR MARKUPS 1

4

i

)

R/8-UFSAR 8

TABLE 15.0-2 (Cont'd)

REAC7OR VESSEL PRESSURIRER IBITIAL 3833 VESSEL AVERAGE PRESSURIBER MATER FEEDWATER

. N TEseERA7URE  ;

8 TIEM EL FONER OUTPUT COOLANT TWWERATURE PRESSURE FAULTS (fest) FImW (GPN) (*F) (PSIA) (ft 3) ('F) 15.1 Increase le Neet Resevel by the '

Secondary System

- Feedwater System S and 3425 399.399 557 and 589.2 2250 450 and 1000 32 and 440  !

Mettenction Cousing en ince.see in F.ed-water Fio.

3425 390.390 509.2 2250 left 440

- Recesolve Incrosse in l Secondary Steam Flow 1 i

- Accidente1 Depressurise- 0 377.609 557 2258 450 50 tion of the Stein Stoem (Suberitical)

• System ,

- Steen System Flying 9 377.600 557 2258 458 50 <

l Fellure (Sebcritical) l 15.2 Decreses in Meet  !

Removal bF the Secondery System 5ycp j 773g

- Loss of Esternet Elec- 3425 399.390 JBStf POW 1890 440 trical Load,and/or '

Turbine Trip

- Loss of Non-Emergency 3579 377.600 565.5 2200 1150 442 [

A-C Power to the Station Aum111eries  ;

15.0-30 REVISION 1 - DECEMBER 1989

TABLE 15.0-5*.

TRIP POINTS AND TIME DELAYS TO TRIP t . . . ASSUMED IN ACCIDENT ANALYSES i

LIMITING TRIP TRIP POINT ASSUMED TIME DELAYS i

FUNCTION IN ANALYSIS (SECONDS) l Power range high neutron 118% 0.5 flux, high setting 1

Power range high neutron 35% 0.5 flux, low setting Variable see 8.0*

Overtemperature AT Figure 15.0-1 Variable see 8.0*

Overpower AT Figure 15.0-1 2.0 High pressurizer pressure ggg,psig 1845 psig 2.0 Low pressurizer pressure 87% loop flow 1.0

(

Low reactor coolant flow t .

(From loop flow detectors)

Undervoltage trip 68% nominal 1.5 I

Not applicable 2.0 Turbine trip 13.7% of narrow range 2.0 .

Low-low steam generator level level span 87.4% of narrow range 2.5 High steam generator level trip of the level span feedwater pumps and closure of feedwater system valves, and turbine trip .

• Total time delay (including RTD bypass loop fluid transport delay effect, bypass loop thermal capacity, RTD time response, trip circuit delay time and channel electronics delay) from the time the temperature difference in the f coolant loops exceeds the trip setpoint until the rods are free to fall.

15.0-36

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l l

l R y re 15.0-l

B/B-UFSAR ,

- e reactor protection system may be required to function -

k fo owing a complete loss of external load to terminate oro heat inpu no prevent DNB. Depending on the magnitude of e load loss, ssuriser' safety valves and/or steam genera r safety valves na be required to open to maintain syst ressure telow allowable 1 its. No single active failure vi prevent opera- .

tion of any a tem required to function. Re r to Reference 2 for a discussio f ATWT considerations.

15.2.2.3 madiolonie connaeuaneam Loss of external load f r full r would result in the operation of the steam 6 ya . This system keeps the al in turbine generator operating t upply ausiliary electrical -

loads. Operation of the at system results in bypassing steam to the condenser, steam umps are not available, st eam 1 ponerator safety and re of valves ieve.to the atmosphere. l Bince no fuel damage postulated to his transient the radiological releas , given in Table 1 . -4, will be less severe than those for t stenaline break acciden analysed in

Bubsection 15. .3.

L5.2.2.4 neiusione results obtained for the turbine trip event ubsection 1 Based .1, t se

15. ) and considerations described icable acceptance criteria for a loss of external los ve 2t in Subsection 15.2.

.i

{ y_: ret.

15.2.3 Turbina Trin 15.2.3.1 Taantifiention of causas and Accident namerintion For a turbine trip, event, the turbine stop valves close rapidly i (typically 0.1 sec.) on loss of trip fluid pressure actuated by one of a number of possible turbine trip signals. Turbine trip initiation signals include:

a. Iow condenser vacuum,

b. low bearing oil pressure,

c. turbine thrust bearing failure,

d. turbine overspeed,

> e. DER d-c power fsilure, and

f. manual trip.

Upon initiation ofSensorsstop valve closure, steam flow to the turbine on the stop valves detect the turbine stops abruptly.

trip and initiate steam dump. The loss of steam flow results in

{ an almost immediate rise in secondary system temperature and 15.2-4 REVISION 1 - DECEMBER 1989

~

B/D-UFSAR.. ,

pressure with a resultant primary system transient as described

( in Subsection 15.2.2.1 for the loss of external load event. For a turbine trip, the reactor would be tripped directly (unless ,

below approximately 30% power on the units where the p-8 modification has been implemented or below approximately 10%

power on the units where the P-8 modification has not been implemented) on a signal from the turbine auto stop oil pressure or the turbine stop valves.

The automatic steam dump system would normally accommodate the excess steam generation. Reactor coolant temperatures and pres-l sure do not significantly increase if the steam dump system and If pressurizer pressure control system are functioning properly.~

the turbine condenser was not available, the excess steam generation would be dumped to the atmosphere and main feedwater flow would be lost, yor this situation, feedwater flow would be maintained by the auxiliary feedwater system to insure adequate residual and decay heat removal capability. Should the steam dump system fail to operate, the steam generator safety valves See Subsection 15.2.2.1 may lift to provide pressure control.

for a further discussion of the transient.

fault A turbine trip is classified as an ANS condition II event, of moderate frequency. See Subsection 15.0.1 for a discussion of condition II events.

A turbine trip event is bounding for loss of external As load, such,loss of condenser vacuum, and other turbine trip events.

I.

this event has been analyzed in detail. Results and discussion of the analysis are presented in Subsection 15.2.3.2.

The plant systems and equipment available to mitigate the conse-quences of a turbine trip are discussed in Subsection 15.0.8 and listed in Table 15.0-7.

15.2.3.2 Annivais of refects and connesuanean Method of Analysis In this analysis, the behavior of the unit is evaluated for a complete loss of steam load from full power primarily to show the adequacy of the pressure relieving devices and also toThe reactor is not tripped demonstrate core protection margins. No credit is taken until conditions for steam dump.

in the RCS result in a trip. Main feedwater flow is termin turbine trip, with no credit taken for auxiliary feedwater to mitigate the consequences of the transient.

The turbine trip transients are analyzed by employing the The detailed digital computer program LOFTRAN (Reference 3).

program simulates the neutron kinetics, RCS pressur The program generator, and steam generator safety valves.

{

15.2-5

4 v

• - 8/B-UTSAR i ..

! computes pertinent plant variables including temperatures, pressures, and power level.

l This accident is analyzed with the improved thermal design plant characteristics and l

procedures as described in WCAP-8567.

i i

initial conditions are discussed.in subsection 15.0.3.

Major assumptions are summarized below:

a. Initial onaratina conditions - initial reactor power, l pressure, and RCS temperatures are assumed to be at l

i their nominal values. Uncertainties in initial i conditions are included in the limit DNBR as

, described in WCAP-8567.

l 1 b. Madarator and Doneler coefficients of Reactivity -

the turbine trip is analysed with both maximum and j minimum reactivity feedback. The maximum. feedback j

cases assume a large negative moderator temperature i

coefficient and the most negative Doppler power

' coefficient. The minimum feedback cases assume a i

least negative moderator temperature coefficient and I the least negative Doppler coefficients. (See Figure 15.0-3.)

c.

naaetor control - from the standpoint of the maximum l pressures attained it is conservativeIftothe assume that the reactor is in manual control. reactor t were in automatic control, the control rod banks would move prior to trip the reduce and severity of 1'

4 the transient.

I

d. stamm malaana - no credit is taken for the operation'

{ of the steam dump system or steam generator The steam generator power-operated relief valves.

pressure rises to the safety valve setpoing where i steam release through safety valve limits Acondary o i

I steam pressure at the setpoint value.

3. Pressurinar Enrav and Tc:: r-Onarmted malief Valves -

l two cases for both the minimum and maximum reactivity I feedback cases are analysed:

1

1. Full credit is taken for the effect of pressuriser spray and power-operated relief valves in reducing or limiting the coolant pressure. Safety valves are also available.

2. No credit is taken for the effect of pressurizer spray and power-operated relief valves in

reducing or limiting the coolant pressure.

1 I

Safety valves are operable.

(

l i 15.2-6

B/B-UFSAR'

f. Feedwater Flow - main feedwater flow to the steam

\ "

~ generators is assumed to be lost at the time of turbine trip. No credit is taken for auxiliary feedwater flow since a stabilized plant condition

will be reached before auxiliary feedwater initiation

is normally assumed to occur. The auxiliary feed-water flow would remove core decay heat following plant stabilization.

g. meneter Trin - is actuated by the first reactor protection system trip setpoint reached. Trip '

signals are expected due to high pressurizer .

pressure, overtemperature AT, high pressuriser water

' level, and low-low steam generator water level.

Except as discussed above, normal reactor control system and engineered safety systems are not required to function. Several cases are presented in which pressuriser spray and power-operated relief valves are assumed, but the more limiting cases where these functions are not assumed are also presented.

The reactor protection system may be required to function fol-lowing a turbine trip. Pressuriser safety valves and/or steam generator safety valves may be required to open to maintain system pressures below allowable limits. No single active failure will prevent operation of any system required to

[ function. A discussion of ATWT considerations is presented in

' Reference 2.

Results The transient responses for a turbine trip from full power i 1 operation are shown for four cases: two cases for minimum -

j

' i reactivity feedback and two cases for maximum reactivity feedback j b- (Figures 15.2-1 through 15.2-8). The calculated sequence of 14 events for the accident is shown in Table 15.2-1.

i T Figures 15.2-1 and 15.2-2 show the transient responses for the

,R total loss of steam load with a least negative moderator tem-g perature coefficient assuming full credit for the pressuriser No credit is b pray and pressuriser power-operated relief valves.

The reactor is tripped by the h41$r I, sken for the steam dump.

I ,;;;;;;i;;; ;;;;;;;; trip channel. The minimum DNBR remains well yf above the limit value. The pressuriser ;;;;;y i;;se; ire actuated and the primary system pressure remains below the 110%

w g

design value. The steam generator safety valves limit the r:1c;

;;; ; ti;; il0%of-%e.'M

t ti; ;;f 'is/p vs.lue.

• secondary steam ;;;.0iti;;h less %e.m 6 A Pesssees.

I Figures 15.2-3 and 15.2-4 show the response for the total loss of i

steam load with a large negative moderator temperature coeffi-

! cient. All other plant parameters are the same as the above.

The DNBR increases throughout the transient and never drops below its initial value. Pressuriser relief valves and steam generator

! l ,

j yac-epestrJ rel.'tf va.lve 5.

• I 15.2-7 i -

a s_

l i .

8/B-UFSAR s

, safety valves prevent overpressurisation in primary and secondary

( systems, respectively. The pressuriser safety valves are not

actuated for this case.

In the event that feedwater flow is not terminated at the time of turbine trip for this case, flow would continue under autcastic 4 control with the reactor at a reduced power. The operator would

! take action to terminate the transient and bring the plant to a i stabilised condition. If no action were taken by the operator

. the reduced power operation would continue until the condenser

hotwell was empti y. Agenerated low-low steam generator water level along with auxiliary feedwater reactor trip would

initiation signals. iliary feedwater would then be used to '

i remove decay heat with t suits less severe than thoce presented in Subsection 15.2. . 'e ve. d vs.lly

! The turbine trip accident was also studied assuming the plant to i be initially operating at full power with no credit taken for the pressuriser spray, pressuriser power-operated relief valves, or steam dump. The reactor is tripped on the high pressuriser

' pressure signal. Figures 15.2-5 and 15.2-6 show the transients with a least negative moderator coefficient (minimum reactivity feedback). The neutron flux remains essentially constant at full power until the react,or is- tripped.

The DBBR 4eeeeeeee-

' never drops below its initial i value. In this case the pressuriser safety valves are actuated, and maintain system pressure below 110% of the design value.

! Figures 15.2-7 and 15.2-8 are the transients with anzimum reactivity feedback with the other assumptions being the same as in the preceding case. Again, the DNBR increases throughout the transient and the pressuriser safety valves are actuated to limit -

primary pressure.

Reference 1 presents additional results of analysis for a complete loss of heat sink including loss of main feedwater.

This analysis shows the overpressure protection that is. afforded by the pressuriser and steam generator safety valves.

15.2.3.3 Radioingical conmaquences The turbine trip transient and steam released for this event are similar to the loss of load transient described in Subsection 15.2.2.3.

There are only minimal radiological conseguences associated with this event, therefore, this event is not limiting. The radio-logical consequences resulting from atmosphere steam dump are less severe than the steamline break event analyzed in subsection 15.1.5.3 since no fuel damage is postulated to occur.

k 15.2-8 REVISIOB 1 - DECEMBER 1989

%-- , , . - - . , . , _ . - - - _ m _ -. . _ . _

B/8-UTSAR' ,

. 15.2.3.4 conclusions l

~

\ Results 6f~the analyses, including those in Reference 1, show that the plarat design is such that a turbine trip presents no hazard to the integrity of the RCS or the main steam system.

Pressure relieving devices incorporated'in the two systems are adequate to limit the maximum pressures to within the design limits.

The integrity of the core is maintained by operation of the reactor protection system, i.e., the DNBR will be maintained above the limit value. The applicable acceptance criteria as listed in Subsection 15.0.1 have been met. The above analysis demonstrates the ability of the MSSS to safely withstand a full load rejection. The radiological consequences in this event will be less than the steam break event analyzed in Subsection 15.1.5.3.

L .2.4 Im J..im um Clu-ux. of ==1n at-mm isointion vaivan J na rtant closure of the main steam isolation valves wo d result n a turbine trip. Turbine trips are discussed 0ubsect n 15.2.3.

15.2.5 Los of condenaar vacuum and other Events musina a Turbiha Trin Loss of condense vacuum is one of the event that can cause a turbine trip. Tur a trip initiating eve s are described in I,ubsection 15.2.3. loss of condenser v cuum would preclude the Use of steam dump to t condenser; how er, since steam dump is a,ssumed not to be avails e in the tu ine trip analysis, no a.dditional adverse effects ould re Therefore, it if the turbine trip we re-claused by loss of condenser cu the analysis i ssults and conclusion contai n Subsection 15.2.3 apply tc loss of condenser vacuum. In ition, analyses for the other possible causes of a turbine rip, as listed in Subsection 15.2.3.1 are covered by Su action .2.3. Possible over-t raquency effects due to turbine ov speed condition are d,iscussed in Subsectio 5.2.2.1 and er not a concern for thi s t ype of event.

15.2.6 Loan of a ==:rannev Ac power to the innt Auri11 arias 1 5.2.6.1 toenw(fication of causam and Accident baserietion L complete oss of nonemergency ac power may result the los s c f all y er to the plant suziliaries, i.e., the reac r coola nt noensate pumps, etc. The loss of power may be aused by pumps, a com ete loss of the offsite grid accompanied by a turb e q en stor trip at the station, or by a loss of the onsite a d ribution system.

- 15.2-9 .

.m_

B/B-UFSAR TABLE 15.2-1 TIME SEOtIENCE OF rvr.nis FOR INCIDENTE WHICH CAUSE A DEEREAEE IN MEAT REMOVAL BY THE RECONDARY SYSTEM TIME ACCIDENT M (see)

Turbine Trip

1. With pressuriser Turbine trip, 0.0 control (minimum loss of main feedwater reactivity feedback) flow e ow%.ah c. AT, : i;t ;;;;;;;i;;; ;;;; g esse reactor trip point g,9 reached .

Init'istion of steam -

g  !

. release from ateam gf I generator safety valves ,

+

Rods begin to drop M f. 7 Peak pressuriser pres- 10.5 dure occurs (1)

~

_ Minisnun DNBR occurs

~

/#. # -

(1) Primary pressure is measured at the pressuriser in the plant. Although the peak pressure in the RCS is slightly higher than the pressuriser pressure, pressuriser pressure is reported for transients that do not challenge RCS integrity.

For transients which challenge RCS integrity, peak RCS pressure is reported. For all transients, it is ensured that peak RCS pressure remains below 2750 psia.

'O r- ? 0;;; ;;t f;;;;;;; i:1;; i;; i;iti;l 7;;;;.

15.2-25

. ~

B/B-UTSAR ,

TABLE 15.2-1 (Cont'd) )

'~

( TIME '

l ACCIDENT EETJ[I (see) (

i 0.0 I 4

2. With pressuriser Turbine trip, l control (maximum loss of main feedwater l reactivity feedback) flow

! Initiation of steam release from steam g-g,g l

generator safety valves j

l Peak pressurizer pressure occurs M"

7. 5 j ~

o n r4e w se*3 vee. Areactor T# s=-trip ir : terr point  ::::::t::

x ~

l 7f reached j 1

Rods,begin to drop

! Minimum DNBR occurs (1) 1 Without pressurizer Turbine trip, 0.0 3.

control (minimum loss of main feedwater i reactivity feedback) flow i  ! High pressurizer pressure $df J

reactor trip point y,3 I reached M

I Rods begin to drop e,. G.3 i

Peak pressuriser pressure M" 1,5

' occurs y

' Initiation of steam M" release from steam 6. .S i ,enerator safety valves g

i Minimum DNBR occurs (1)

Turbine trip, 0.0

4. Without pressuriser control (maximum loss of main feedwater l reactivity feedback)

High pressuriser pressure Aff reactor trip point 9,3 reached (1) DNBR does not decrease below its initial value.

15.2-26 . ,

l i

B/B-UFSAR .,

. l

. . . . . TABLE 15.2-1 (Cont'd)

TIME ACCIDElfT EEERI (nme)

Rods begin to drop NT 3

6. 3 i Peak pressuriser pressure J,ef' l occurs 7,0 l

' Initiation of steam 3,,f' release from steam g,g generator safety valves Minimum DNER occurs (1) l b - - a s ma -- - ----- Meir f t:f- :t;: fi;r 1" i t ower stops Low-low steam generator 52 water level trip -

Rods begin to drop 54 Reactor coolant p 54 begin to coastdown l

Four steam gene tors 11:

begin to recei auxiliary fe water frca '

one motor o von auxiliary eedwater ump Co a liary feedwater 259 is d vered to the sta nerators k wate level in 310 ressuriser curs .

Core decay hea decreases -32!

to auxiliary f stor heat removal cape ty L0ss of Normal F - Main feedwater flow 10 water Flow stops Low-low steam generator 52 water level trip Rods begin to drop

{

15.2-27 REVISION 1 - DECEMBER 1989

B/B-UFSAR TABLE 15.2-1 (Cont'd) f TIME ACCIDElrr EYEET faac) 1

, Peak water level in 113 l

pressuriser occurs t

]

l 1

(1) DNBR does not decrease below its initial value.

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N h llchJs'ni r RJR81NE TRIP EVENT WITHOUT PRESSUREER

SPRAY AND POWER-OPERATED RELIEF VALVES,

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i APPENDIX C SIGNIFICANT HAZARDS EVALUATION I 1

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SIGNIFICANT HAZARDS EVALUATION l

_ BYRON /BRAIDWOOD MSSV LIFT SETPOINT TOLERANCE TECHNICAL SPECIFICATION CHANGE INTRODUCTION:

Pursuant to 10CFR50.92, each application for amendment to an operating license must be reviewed to determine if the proposed change involves a significant hazards consideration. The Commission has provided standards for determining whether a significant hazards consideration exists (10CFR50.92(c)]. A proposed amendment to an operating license for a facility involves no significant hazards consideration if operatian of the facility in accordance with the proposed amendment would not: 1) involve a significant increase in the probability or consequences of an accident previously evaluated, or 2) create the possibility of a new or different kind of accident frcm any accident previously evaluated, or 3) involve a significant reduction in a margin of safety.

DESCRIPTION OF AMENDMENT REQUEST: -

The purpose of this amendment request is to revise Technical Specification Section 3/4.7 to relax the main steam safety valve (MSSV) i lift setpoint tolerance from 1% to t3%. The currently specified tolerance of 1% of the setpoint has been difficult to meet when the valves are tested. Commonwealth Edison Company (Ceco) has found that over an operating cycle, the setpoint of the MSSVs changes by more than 1% from the original set-pressure. As a nsult, the plant is placed in an ACTION statement and must take immediate steps to avoid a violation.

The ASME Code requires that the valves 1f ft within 1% of the specified setpoint (NB-7512.2). The code also states that the valves must attain rated lift (i.e., full flow) within 3% of the specified setpoint (NB-7512.1). This evaluation will form the basis for takin the ASME Code with respect to the lift setpoint tolerances.g exception As definedto in NB-7512.2, exceptions can be made to the code providing the effects are accounted for in the accident analyses, specifically, the Overpressure Protection Report.

BASIS FOR NO SIGNIFICANT HAZARDS DETERMINATION:

l The effects of increasing the as-found. lift setpoint tolerance on the main steam safety valve have been examined, and it has been determined that, with one exception, the current accident analyses as presented in the UFSAR remain valid. The loss of load / turbine trip event was analyzed in order to quantify the impact of the setpoint tolerance relaxation. As previously demonstrated in this evaluation, all applicable acceptance criteria for this event have been satisfied and the conclusions presented in the UFSAR are still valid. Thus, the proposed Technical Specification change does not constitute an unreviewed safety question, and the non-LOCA accident analyses, as presented in the report, support the 1

proposed change.

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~ __ _ _ _ ____ . _ . _ ___ _ _. _ _ _ _ _ _ _ _ _ _ . _ _

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1 j The effect of a increase in the allowable Main Steam Safety Valve set j pressure tolerance from +1% to +3% on the FSAR LOCA analysis has been

. evaluated. In each case the applicable regulatory or design limit was j satisfied. Specific analyses were performed for small break LOCA assuming the current MSSV Technical Specification set pressures plus the proposed j additional 3% uncertainty. The calculated peak cladding temperatures were well below the 10CFR50.46 22000 F limit.

j Neither the mass and energy release to the containment following a i

postulated loss of coolant accident (LOCA), nor the containment response

following the LOCA analysis, credit the MSSV in mitigating the consequences

. of an accident. Therefore, changing the MSSV lift setpoint tolerances would i have no impact on the containment integrity analysis. In additon, based on

the conclusion of the transient analysis, the change to the MSSV tolerance will not affect the calculated steamline break mass and energy releases  ;

l inside containment. l The proposed change has been evaluated in accordance with the Significant I

Hazards criteria of 10CFR50.92. The results of the evaluation demonstrate l

that the change does not involve any significant hazards as described below.

1. A significant increase in the probability or consequences of an accident 1 previously evaluated. -

Relaxation of the MSSV setpoint tolerance from 11% to 3% does not increase the probability or consequences of an accident previously ]

evaluated. Component and system performance will not be adversely affected since equipment and system design criteria continue to be met.

The MSSVs do not initiate any accident discussed in the FSAR. Neither the mass and energy release to the containment following a postulated loss of coolant accident (LOCA), nor the containment response following the LOCA analysis, credit the MSSV in mitigating the consequences of an -

accident. Therefore, changing the MSSV lift setpoint tolerances would have no impact on th consequences of an accident.

2. Create the possibility of a new or different kind of accident from any accident previously evalcated.

The possibility for an accident or malfunction of a different type than evaluated previously in the safety analysis report is not created.

Increasing the lift setpoint tolerance on the MSSVs does not introduce a ,

new accident initiator mechanism. No new failure modes have been '

defined for any system or component important to safety nor has any new limiting single failure been identified. ,

l

3. Involve a significant reduction in a margin of safety.

l The margin of safety &s defined in the basis of the Technical Specifications is not significantly reduced by the change in the MSSV lift setpoint tolerance. All acceptance criteria with respect to fuel, RCS pressure boundary, and containment integrity continue to be met.

sp 9

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APPENDIX D MARKED UP TECHNICAL SPECIFICATICN SECTIONS S

_ . _ _ _ _ _ . _ _ _ _ . _ _ _. _ _ _- _ . . _ _ _ ~

IABLE 3.7 ,

-- STEAM LINE SAFETY VALVES PER LOOP ._

VALVE NUMBER 3

! LIFT SETTING (::20* di M5013(A-D ORIFICE SIZE-i 1235 psig ,

M5014(A-0) 16 in2 1220 psig '

i M5015(A-0) 16 in2 l 1205 psig -

16 in2

. M5016(A-0)

' 1190 psig 16 ina MS017(A-0) 1175 psig 16 in*

3

)

i "The lift setting pressure shall correspond to ambient condition valve at nominal opr, rating temperature and pressure.

! e 3n g4.J gJues sLJi Le sef fo 21 % Volerance.

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BYRON - UNITS 1 & 2 3/4 7*3 .

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.- - TA8LE 3.7-2 l

STEAM LINE SAFETY VALVES PER LOOP l 3 VALVE NUMBER LIFTSETTING(d): P ORIFICE SI.i MS013(A-D) 1235 psig 16 in2 j M5014(A-0) 1220 psig 16 in2 i

M5015(A-D) 1205 psig

! 16 ins MS016(A-D) 1190 psig

16 in2

! MS017(A-D) 1175 psig 16 in8 l

s "The lift setting pressure shall correspond to ambient conditions of the valve at nominal operating temperature and pressure.

• AU. Tested VMut5 5HKL 6t. sgf to t \% tottnace.

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4 BRAIDWOOO - UNITS 1 & 2 3/4 7-3 b-m.

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3/4.7 PLANT SYSTEMS -

i BASES f 3/4.7.1 TURBINE CYCLE 4

l 3/4.7.1.1 SAFETY VALVES

! The OPERA 8ILITY of the main steam line Code safety valves ensures that i the Secondary Coolant System pressure will be limited to within 110% (1320 psia)

. of its design pressure of 1200 psia during the most severe anticipated system

! operational transiertt. The maximum relieving capacity is associated with a

tureine trip from 1025 RATED THERMAL POWER coincident with an assumed loss of

! condenser heat sink (i.e., no steam dumps to the condenser). -

/ w 'Iv56RT' Tex r Aete.

The specified v$1ve Tift settings and relieving capacities are in l

i accordance with the requirements of Section III of the ASME Boiler and Pressure i Code,1971 Edition.%/The total relieving capacity for all valves on all of

{ the steam lines is 17.958 x 10' lbs/h which is 1195 of the total secondary l

steam flow of 15.135 x 108 lbs/h at 100% RATED THERMAL POWER. A minies. of

} two OPERA 8LE safety valves per steam generator ensures that sufficient

relieving capacity is available for the allowable THERMAL POWER restriction i in Table 3.7-1.

4 l STARTUP and/or POWER OPERATION is allowable with safety valves inocerable within the limitations of the ACTION requirements on the basis of the recuction in Secondary Coolant System steam flow and THERMAL POWER required by the recuced Reactor trip settings of the Power Range Neutron Flux channels. The Reactor j Trip Setpoint reductions are derived on the following bases: ,

1 For four loop operation:

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SP =

X Y} x (109).

Where:

SP = Reduced Reactor Trip Setpoint in percent of RATED THERMAL POWER, 1

V = Maximum number of inoperable safety val,ves per steam line, BYRON - UNITS 1 & 2 8 3/4 7-1

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3/4.7 PLANT SYSTEMS f j  ;

i BASES

! 3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES l l The OPERA 81LITY of the main steam line Code safety valves ensures that j the Secondary Coolant System pressure will be limited to within 110% (1320 psia) of its design pressure of 1200 psia during the most severe anticipated sys. tem l operational transient. The maximum relieving capacity is associated with a i

turbine trip from 102% RATED THERMAL POWER coincident with an assumed loss of condenser heat sink (i.e.,'no steam dumps to the condenser).

7 ADp 745dtr' TET 96t4 The specified ifalve lift settings and relieving capacities are in ,

l accordance with they equirements of Section III of the ASME Boiler and Pressure Code, 1971 Edition. The total relieving capacity for all valves on all of l

the steam lines is 17.958 x 10* lbs/h which is 119% of the total secondary A minimum of steam flow of 15.135 x 108 lbs/h at 100% RATED THERMAL POWER.

two OPERA 8tE safety valves per steam generator ensures that sufficient relieving capacity is available for the allowable THERMAL POWER restriction in Table 3.7-1.

STARTUP and/or POWER OPERATION is allowable with safety valves inoperable within the limitations of the ACTION requirements on the basis of the reduction i in Secondary Coolant System steam flow and THERMAL POWER required by the reduced The Reactor  !

Reactor trip settings of the Power Range Neutron Flux channels. t Trip Setpoint reductions are derived on the following bases: .

For four loop operation:

Sp = (X) - (Y)(V) x (109).

X Where:

SP = Reduced Reactor Trip Setpoint in percent of RATED THERMAL POWER, V = Maximum number of inoperable safety valves per steam line, i

i 8 3/1 7-1 .

BRAIDWOOD - UNITS 1 & 2 I

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Insert  ;

The Technical Specification requirement that Steam Line Safety Valves be set to within 21% tolerance when found outside_this range is consistent with Section XI of the ASME Boiler and Pressure Code. The specification that Steam Line Safety Valves may operate witn setpoint tolerances to within t3% is supported by " Commonwealth Edison Company, Byron &

, Braidwood Stations Units 1 & 2 Overpressure Protection t Report." l l i 1

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SARGENT& LUNDY ENGINEERS

, rounoso seen as EAST MoNRot STREET cMicAoo. wmois M>eos asia ...-sooo October 4, 1990 Project No. 8637-50 File Nos. 7.1, 7.5 (JGS-114)

Commonwealth Edison Company Byron /Braidwood Stations Units 1 and 2 MAIN STEAM SAFETY VALVE SETPOINT TOLERANCE INCREASE ANALYSIS System Codes: AF, MS Mr. R. E. Waninski .

Nuclear Engineering Department Commonwealth Edison Company 1400 Opus Place Executive Towers West III, Suite 400 Downers Grove, Illinois 60515

Dear Mr. Waninski:

We recently completed a study to analyze a change in the Main Steam Safety Valve (1/2MS013A-D, 1/2MS014A-D, 1/2MS015A-D, 1/2MS016A-D, 1/2MS017A-D) setpoint tolerance as described in my -

June 25 and August 17, 1990, letters to you. The current system design is based on the setpoint tolerance per Technical Specification 3/4.7.1 of ilt. The above referenced letters summarized the effect of a change in the positive tolerance to

+3% on the Main Steam system piping, piping supports and piping penetrations and the Auxiliary Feedwater system capacity.

This letter is to confirm our recent conversation that a change in the negative tolerance to -34 does not affect the results of our previous analysis. The Main Steam system piping analysis and Auxiliary Feedwater system capacity design basis is not affected by a change in the negative tolerance. It should be noted however, that an increase in negative tolerance increases the potential for spurious valve openings.

If you have any questions concerning this matter, please feel free to contact either Mr. J. R. Meister at 312-269-6882 or me at 312-269-6708.

4

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CARSENT Q LUNDY '

ENGINCERO CHICA30 g, Mr. R. E. Waninski October 4, 1990 Commonwealth Edison Company Page 2 Yours very truly, J. G. Saltarelli Senior Mechanical Project Engineer I

JGS:cl Copies:

F. G. Lentine K. L. Kofron R. Pleniewicz E. R. Wendorf i l

D. B. Wozniak CHRON System /Mailroom Supervisor B. Rybak W. C. Cleff R. J. Netzel/S. F. Putman M. S. Leutloff J. R. Meister D. V. Radice R. J. Rakowski File Nos. 7.1, 7.5 -

JGS2L/JGS114.cl

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I 6

j SARGENT & LUA%Y ENGINEERS

, roumotosees se EAST wowmot svart?

l CH4CA00, ILLINOls 60603

<aisia...noco August 17, 1990 Project No. 8637-50 File Nos. 7.1, 7.5 (JGS-110)

Commonwealth Edison Company Byron /Braidwood Station Units 1 and 2 MAIN STEAM SAFETY VALVE SETPOINT TOLERANCE INCREASE ANALYSIS System Codes: AF, MS Mr. R. E. Waninski l

Commonwealth Edison Company.

I Nuclear Engineering Department 1400 Opus Place, Suite 400 l

Downers Grove, Illinois 60515 1

Dear Mr. Waninski:

We have completed the second phase of our study to analyze an increase in the Main Steam Safety Valve (1/2MS013A-D, 1/2MS014A-D, 1/2MS015A-D, 1/2MS016A-D, 1/2MS017A-D) setpoint tolerance as '

I referenced.in my June 25, 1990 letter to you. The current system design is based on the setpoint tolerance of 14 as specified in Technical Specification 3/4.7.1. The affect on the Auxiliary Feedwater system capacity of the proposed change in positive tolerance to +3% was the second phase of our study.

The change in positive tolerance to +3% will result in an increase in the maximum steam generator pressure from 1225 psia, the current system design basis, to 1250 psia based on discussions with Westinghouse. The resultant affect of the 3 increased steam generator pressure (.1250 psia) on the Auxiliary Feedwater system capacity was evaluated for two limiting accident scenaries. In accordance with your request, AF system capacity was evaluated for the feedwater pipe rupture and loss of main feedwater (station blackout) accident scenarios at an unfaulted steam generator pressure of 1250 psia. The scenario results are summarized as follows:

Feedwater Pine Runture

. Three intact steam generators at 1250 psia

. One faulted steam generator at 14.7 psia

. One AF pump (motor driven) operating

. Resulting AF system flow to three intact steam generators is 458 gym

. . . . _ _ . ._ _ _ _ _ .._m__ m __________.m .. _ . _ . _ _

SARGENT Q LUNDY '

. GNDINxuna CMICACO ,

Mr. R. E. Waninski August 17, 1990 1 Commonwealth Edison Company Page 2 l

l Loss of Main Faadwater/ Station Blackout i

. Four intact steam generators at 1250 psia l . One AF pump (diesel driven) operating

. Resulting AF system flow to four intact steam generators is 763 gpa I

l The following listing summarizes the basis and assumptions l

utilized in the Auxiliary Feedwater system capacity evaluation:

l

. 1/2AF005A-H valves in full open position

. AF pump performance per vendor manual curves

. Condensate Storage Tank empty, water Elevation 399'-9" for l Braidwood Station was utilized for conservatism

. Suction piping friction losses for Braidwcod Station Unit 1, which has the highest calculated pressure drop of all four units, were utilized for conservatism.

. Discharge piping was modeled using Byron Unit 1 as-built piping isometrics. The physical differences between discharge piping at all four units will have a negligible affect on the calculated flow rates.

. Intact steam generator pressure was assumed to be 1250 psia as specified by Westinghouse and faulted pressure was conservatively assumed to be 14.7 psia.

. Pump discharge static head was based on pump centerline and a maximum intact steam generator water level of -

Elevation 448'-10 " which is the water level instrument upper tap centerline. A fmulted steam generator water level of Elevation 439'-0", which corresponds to the upper steam generator nozzle elevation, was utilized.

. Piping frictional losses were conservatively calculated based on dirty (old) steel pipe with an absolute roughness of 0.036".

. A conservative pump recirculation flow rate of 100 gpa was assumed.

In conclusion the above results completes our evaluation of the Main Steam Safety Valve setpoint tolerance increase. We also request that you confirm with Westinghouse that the containment mass / energy release rates are not affacted by the increased setpoint tolerance.

.. - . - . . _ . - . - - - . . _ . - _ ~ _ - ~ ~ _ _ . . - . . .

CAR 2ENT O LUNDY ENOINEERO cMecAso .,

Mr. R. E. Waninski August 17, 1990 Commonwealth Edison Company Page 3 1

If you have any questions concerning this matter or require any l additional flow scenario evaluations, please feel free to contact l either Mr. J. R. Meister at 312-269-6882 or me at 312-269-6708. l Yours very truly, e.4.he J. G. Saltarelli Senior Mechanical Project Engineer JGS:cl .

Copies:

F. G. Lentine K. W. Kofron '

R. Pleniewicz E. Wendorf D. B. Wozniak '

S. F. Stimac CHRON System /Mailroom Supervisor B. Rybak W. C. Cleff l R. J. Netzel/S. F. Putman .

l M. S. Leutloff J. R. Meister D. V. Radice R. J. Rakowski File Nos. 7.1, 7.5 JGS2L\JGS110.cl r

SARGENT & LUNkiY i ENGINEERS l

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CMICA00. ILLIN0ls SOSO3 I tala t see.aoco June 25, 1990 Project No. 8637-50 File Nos. 7.1, 7.5 (JGS-104)

Commonwealth Edison Company Byron /Braidwood Stations Units 1 and 2 -

MAIN STEAM SAFETY VALVE SETPOINT TOLERANCE INCREASE ANALYSIS System Codes: AF, MS l

Mr. R. E. Waninski .

Commonwealth Edison Company l Nuclear Engineering Department

! 1400 Opus Place, Suite 400 l Downers Grove, Illir.ois 60515

Dear Mr. Waninski:

l We have recently completed the initial phase of our study to analyze a change in the Main Steam Safety Valve (1/2MS013A-D, 1/2MS014A-D, 1/2MS015A-D, 1/2MS016A-D, 1/2MS017A-D) setpoint >

tolerance. The current system design is based on the setpoint -

tolerance per Technical Specification 3/4.7.1 of ilt. We are currently reviewing the affect of a change in the positive tolerance to +34.

Our init.ial phase of the analysis was to evaluate the Main Steam piping due to the higher pressure at the maximum safety valve setpoint including positive tolerance. Piping, piping supports and piping penetrations associated with subsystems 1/2 MS01 were evaluated. Specifically the main steam piping from the MSIV to containment penetration and the safety valve vent lines were analyzed in detail. The analysis concluded that the existing system configuration can accommodate a change in the main steam safety valve tolerance to +3% without any modification.

The second phase of our evaluation is the affect of the tolerance increase on the Auxiliary Feedwater system capacity. This evaluation is currently ongoing and preliminary results are expected by July 2, 1990.

CARGENT O LUNDY' ENGINEEQO CMicAso ..

Mr. R. E. Waninski June 25, 1990 l Commonwealth Edison Company Page 2 If you have any questions concerning this matter, please feel free to contact either Mr. J. R. Meister at 312-269-6882 or me at  !

312-269-6708.

Yours very truly, o

l l

J. G. Saltarelli Senior Mechanical Project Engineer JGS:cl Copies: l F. G. Lentine R. E. Querio R. Pleniewicz G. Groth D. B. Wozniak CHRON System /Mailroom Supervisor B. Rybak W. C. Cleff R. J. Netzel/S. F. Putman M. S. Leutloff ,

l J. R. Meister -

D. V. Radice l R. J. Rakowski File Nos. 7.1, 7.5 JGS1/JGS104.wp

M: --

~ ll .. .-

l April 25, 1990 AP ' t r.- i RSA:90-039 Mr. E. D. Swartz

Subject:

B/B Main Steam Safety Valve Setpoint Change Evaluation with respect to SGTR analysis

Reference:

Letter to H. Naughton from C. A. Moerke dated March 13, 1990 l

Per PHR Systems request (Reference), NFS has evauated the proposal to relax the MSSV setpoints to 3'l as found and reset to 1% on the results of the B/B SGTR Rev. I analysis. NFS has determined there would be no impact on SGTR. It did not decrease or increase either margin to overfill case results or offsite dose case results. The maximum pressure in the ruptured steam '

generators for both licensing cases never reached the lift setpoint corresponding to the lowest set MSSV 'with a -R drift. Lift setpoints higher i than nominal likewise have no impact on the results of either SGTR case.

As found setpoints would have to drift to 1111 psig to impact the '

SGTR results. At this lift pressure the MSSV would impact the margin to overfill case. Lift at 1111 psig represents a -5.4% drift. More significant impact would result from a drift below 1086.6 psig, especially for the offsite dose case. Additional radionuclides would be released increasing the offsite dose with this -8.7% drift on the lowest set MSSV.

Please note that the SGTR analysis of record was performed by Westinghouse as documented in the FSAR. A SGTR analysis performed by NFS was submitted to the NRC in August of 1988. In April of 1990, NFS provided a Revision I to the SGTR analysis, which superceded the previous report. It is not known when the staff will complete its review and issue an SER.

1 Currently, NFS has not received any staff questions concerning SGTR analyses.

Therefore, NFS recommends that the new MSSV setpoint tolerances also be evaluated against the SGTR analysis of record in order that no delays will be experienced in their implementation.

If you'have any questions or comments, contact John Freeman at ext. 3856, General Office.

1 Kenneth N. Kovar W. W Safety Analysis Supervisor Nuclear Fuel Services KNK:JMF:bl ID:ZBXL:101:7 cc: K. B. Ramsden R. E. Wantnski '

J. M. Freeman /J. E. Ballard T. Schuster (NLA) i J. Langan

. L. Bush i G. Magner F. Lentine R. Gestor I W. F. Naughton/NFS-CF l RSA-CF  ;

e