L-90-469, Byron/Braidwood Units 1 & 2 Increased Main Steam Safety Valve Setpoint Tolerance Safety Evaluation

Byron/Braidwood Units 1 & 2 Increased Main Steam Safety Valve Setpoint Tolerance Safety Evaluation

ML20065A159
Person / Time
Site:	Byron, Braidwood
Issue date:	10/31/1990
From:	Rarig B, Sterdis R WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:
Shared Package
ML20064N793	List: L-90-469, Byron/Braidwood Units 1 & 2 Increased Main Steam Safety Valve Setpoint Tolerance Safety Evaluation ML20064N791 ML20064N802
References
SECL-90-469, NUDOCS 9403310051
Download: ML20065A159 (110)

Text

9 SECL 90-469 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 & 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) Yes X No A change to the plant as described in the FSAR?

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

(3.3) Yes No X 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 No X Will the probability of an accident previously evaluated in the FSAR be increased?

(4.2) Yes No X Will the consequences of an accident previously evaluated in the FSAR be increased?

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

(4.4) Yes No X Will the probability of a malfunction of equipment important to safety previously evaluated in the FSAR be increased?

(4.5) Yes No X Will the consequences of a malfunction of equipment important to safety y eviously evaluated in the FSAR be increased?

(4.6) Yes No X 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 X Will the' margin of safety as defined in the bases to any technical specifications be reduced? .

94o3310051 940323 PDR ADOCK 05000454 1 P PDR

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 ,

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 follow evaluation ,{ngsummarizesthejustificationbaseduponthewrittensafety 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/ Description of Change:

Table 15.0-2. Table 15.0-5. Fioure 15.0-1. and Section 15.2.3 were revised based on the new analyses (DT orotection and LOL/TT).

6) SAFETY EVALUATION APPROVAL LADDER:

6.1) Prepared by (Nuclear Safety): dNd Date: tobo/9o B.E.Rarigg 3

6.2) Nuclear Safety Group Manager: Date: f

/

R.~J./Sterdis 2

m BVRON/BRAIDWOOD UNITS 1 AND 2 INCREASED MAIN STEAM SAFETY VALVE SETPOINT 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 (11%) 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 (NB-7512.1). This 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 E SU 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 l

lift'setpoint tolerances involves a change to the Byron and Braidwood technical specifications and requires a licensing amendment request, this evaluation will be performed using the method outlined under 10CFR50.59 to provide the bases for the determination that the proposed change does not involve an unreviewed safety question. In 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).

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 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 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 i 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.

l l

l 4

TABLE 1 DNB DESIGN BASIS TRANSIENTS

-EVENT 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 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 Reactor 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 Subcritical 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 Relief Valve Startup of an Inactive Reactor Coolant Pump 15.4.4 CVCS Malfunction (Boron Dilution) 15.4.6 5

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 prior 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 M5SVs 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 Dilution) 15.4.6 l 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 i 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.

EVENT 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 determine 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 I core remains covered and in a coolable geometry (FLB). These transients are listed below.

EVENT UFSAR Section Loss of Non-Emergency AC Power 15.2.5 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 setpoint tolerance because the calculations determining 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 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 to operate since they conservatively minimize the amount of AFW available for cooling. These transients assume an AFW flow rate of 153 gpm per steam generator. If the valves were inoperable or failed 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.

The feedline break event results in a faulted steam generator that depressurizes to atmospheric pressure. As a result, the AFW flow control valves are assumed to fail, minimizing the amount of AFW 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 to the faulted loop. Since there is no method available to throttle 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.

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 offsite power available. Based on subsequent calculations, it was 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 gpm). 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 tolerance, this 7

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 open 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 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 MSSV 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 required 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 ho~urs), 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 pressu"e considered in the mass calculations. Thus, the existing releases include a reseat pressure equal to 7% below the lowest Technical Specification lift setpoint. As long as the valves continue to reseat within this pressure range, the current mass releases remain valid.

8

1 3.1.7 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 immediate 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 safety valves. The reactor will eventually be tripped by one of the other reactor protection system (RPS) functions; specifically, overtemperature AT, high pressurizer pressure, or low-low steam generator water level.

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 potentially be opening at a higher pressure due to the increase in the lift setpoint tolerance, it is necessary to analyze this transient in order to demonstrate that all the applicable ~ acceptance criteria are satisfied. 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 or 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 i 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 I end-of-life conditions, respectively.

c. Turbine trip was analyzed both with and without. pressurizer j 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

l

d. The steam generator PORV and steam dump valves 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.

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.

g. The MSSVs were assumed to lift 3% above the Technical ,

Specification setpoints and were assumed to be full open 5% above I the setpoints. This is consistent with the 2% difference between i lift and rated flow currently included in the code. l

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

249 lbm/sec.

3.1.7.2 Analysis Results 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.

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 event under EOL 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 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 E0L 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

pressurizer relief valves and sprays 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 val ue.

~

r Case D:

Figures 11 through 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 abcVe 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 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 minimum DNBR for each case is greater than the limit value. The peak primary and secondary pressures remain below 110% of design at all times.

I 11 l

1

TABLE 2

. . . . . - TURBINE TRIP SEQUENCE OF EVENTS TIME ACCIDENT EVENT (sec)

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 EVENT isec)

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

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 5

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 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 l

The effects of increased tolerances for the Main Steam Safety Valve ,

(MSSV) setpoints on the LOCA. safety analyses has been previously l performed for VANTAGE 5 fuel. The current Technical Specification l setpoints with rated flow is given below for easy reference. The l effect of either increasing or decreasing the setpoint by 3%,  ;

depending upon the direction of conservatism, has been evaluated for j the LCc.A snalyses. l MSSV NUMBER T/S SETPOINT RATED FLOW ACTUAL FLOW MS017A,B,C,D 1190 (PSIA) 841,427 934,918 l

1 14

MS016A,B,C,0 1205 (PSIA) 852,039 946,710 MS015A,B,C,D 1220 (PSIA) 862,652 958,502 MS014A;B,C,D 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 3% 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 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.

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 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 l secondary pressure. Since the RCS pressure is controlled by the  !

steam generator secondary pressure through the MSSVs, a decrease in l 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 provide increased safety injection water to the RCS, which would act to reduce the calculated peak clad temperature. Therefore, a -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 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 anaiysis results found in the FSAR calculate that the peak loads occur within the first 500 milliseconds of the transient. This occurrence is well before any automatically operated safety feature has rerponded 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.

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

There is no effect due to increasin'g the tolerance of the steam generator Main Steam Safety Valve (MSSV) setpoints from 1% to i3% on short or long term 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 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 performed to calculate the consequences for the long term design basis LOCA event.

The short term mass and energy release calculation is terminated 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 1

16 i

plus S1 actuation t:ere assumed to occur on low pressurizer pressure.

A loss of offsite' power was also assumed to occur at the time of reactor trip, thus the steam dump system was assumed to be unavailable. The energy transfer from the primary system following reactor and turbine trip causes the secondary side pressure to increase rapidly after reactor trip until the steam generator power operated relief valves (PORVs) and/or safety valves lift to dissipate the energy. For the SGTR analysis, it was assumed that the secondary 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 30 minutes after the accident. A change in the main steam safety valve setpoint tolerance to -3% will result in the secondary pressure being maintained at a lower pressure during this 30 minute period, thereby increasing the primary to secondary pressure differential.

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

An evaluation was performed to determine the effect of decreasing the safety valve setpoint by -3% with respect the SGTR analysis in the FSAR. It is noted that this evaluation was performed in conjunction with the other changes associated with the VANTAGE-5 fuel upgrade, 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 still less than the conservative value reported in the FSAR for the SGTR event by approximately 2%. It is noted that the reactor coolant 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.

Therefore this assumption would not be affected by the aforementioned 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 exists in the FSAR report), such that the offsite radiation doses are less than the results reported in the FSAR. Therefore, it is 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.

3.2.6 Het Leg Switchover of the ECCS to Prevent Potential Boron 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 valves. However, an evaluation is required to assure that adequate 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 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> based on large break LOCA assumptions. The calculated core 17

boil-off rate at 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> could be approximately 20 lbm/sec. The minimum ECCS flow required for delivery to the hot legs following switchover is 1.5 times the boil-off rate for a 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 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 lbm/sec at 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 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 3% 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 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 2200 0 F limit.

3.3 Containment Intecrity 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.

i 18 J l

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 uncertainties. 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 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 iS%, use of these procedures will ensure that the secondary pressure remains within acceptable limits.

4.0 DETERMINATION OF UNREVIEWED SAFETY OVESTION

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 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 initiated to protect the secondary systems from overpressurization.

Sufficient margin exists between the normal steam system operating pressure and the valve setpoints with the increased tolerance to preclude an increase in the probability of actuating the valves.

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 below the current Technical 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 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 specified limits of the licensing basis. Although increasing the valve setpoint will increase the steam release from the ruptured steam generator above the FSAR value by approximately 2%, the SGTR analysis 19

I J

indicates that the calculated break flow is still less than the value l reported in the FSAR. Therefore, the radiological analysis indicates I 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 the i existing mass releases used in the offsite dose calculations for the  !

remaining transients (i.e., steamline break, rod ejection) are still j 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 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 reactor protection system, any of the protection setpoints, or any Qther 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 respcase 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. Hay 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

n

7. Will the margin 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 I 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 i

10CFR50.46. Thus, there is no reduction in the margin tc safety. I

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 i preceding analyses and evaluations have determined that operation with the MSSV setpoints within a 3% tolerance about the nominal values will have no adverse % pact upon the licensing basis analyses, as well as the steamline breax mass & energy release rates inside and outside of containment. In addition, it is concluded that the 3% tolerance on the MSSV setpoint does not adversely affect the overpower or overtemperature protection system. As a result, adequate protection to the core limit lines continues to exists. Therefore, all licensing basis criteria continue to be satisfied and the conclusions in the

'1AR 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 1% 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 1 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 a . _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ - _ _ .

5)

Byron /Braidecod 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, I June 1972.

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.

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

WCAP-10961-P, October 1985.

i J

22 J

I l

1 1

h

\

OVERTEMPERATURE AT TRIP

\

\ t g

-t-- ,

65-s

~'-4 ,,

OVERP0tfER AT TRIP g g '

\

g g ~~_,

\ .

\ \ '.,

\ \

g

\

60- \

\

\ \

g

' g ga s

%e '

2460 PSIA-t g

\

\

g

\- \

g

\ ip '

g g i

\ \

g \

\ \

2250 PS!A

• 50- \

\

[ \

g \ \

e g . \ \

~

\ g g 45- A\ g \ STEAN GDIERATOR

\

g \ \ SAFETY VALVES OPEN

\

g \ \

g d\ \

g \ \ ,

40' g \ \ j

' SIA g 1860 PSIA g \

g \ \

g \ \

55- g g \

\ \

g s

\

• g

\

g 015 LIMIT LINES

\

\

\  %

g 90 585 SN 5% 600 695 sig Si5 628 625 658 655 648 T ave 10Fl BYRON /BRAIDWOOD STATIONS FIGURE 1

~

ILLUSTRATION OF OVERTENPERATURE

'AND OVERPOWER DELTA T PROTECTION m- ^ - - - -

2600.

2500.

.E. . . - -

E '2400.

u

$ 2300. '

8 u.

A 2200.

O

~

E 2100.

S O

g 2000.

1900.

1800.

1800.

h 1600.

b w '

5 1400.

d 0

g 1200.

O

~ -

p 1000.

3 0

sw

~" 300.

600.

0. 10. 20, 30, 40, 50. 60.- 70. 40. 90. 100.

TIME (SEC)

BYRON /BRAIDW000 STATIONS FIGURE 2 TUR8INE TRIP EVENT WITHOUT.

PRESSURE CONTROL, NININUN REACTIVITY FEEDBACK w- F

1 1.4

- i f.

z 1.2 t

r . . . _

9.

L o .1.

S 3 .8 3 3 b l nt b \

w 8

a.

4 g

b.

.8 .2 z

0, t 5.

.4.5 -

4.

o 3.5 ,

E

=

]

2.5 2.

1.5 -

1.

0 to 20 30 40 50 60 70 80 90 100 ,

TIME (SEC)

BYRON /BRAIDWOOD STATIONS-FIGURE 3 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, '

NININUN REACTIVITY. FEEDBACK. >

r r

640 630

,l 8 620 -

1 9 i w 610 ,

95 600 -

t 5 590 -

8 580 y 570 E 560 '

o u

550 540 600 C 590 5 -

e g 580 m

E 5

g 570 W

O 560

_d.

U o

" 550 -

540 0- 10 20 30 40 50 60- 70 80- 90 100 TIME (SEC) 8YRON/8RAIDWOOD STAT!0NS' ,

FIGURE 4-i TUR8INE TRIP EVENT WITHOUT'-

PRESSURE CONTROL, MININUN REACTIVITY FEEDBACK

2600.

2500.

f}, .-

E 2400.

w h 2300.

O N 2200.

8 N

g 2100. ,

8

{ 2000.

1900.

1800.

1800.

E 1600.

C_

Y D 1400.

0 y 1200.

=

E

~ _ _ .

~

1000.

u

" 800.

600.

0, 10. 20. 30, 40. 50. 60. 70. 20. 90. 100.

TIME (SEC)

BYRON /BRAIDWOOD STATIONS FIGURE 5 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, MAXIMUM REACTIVITY FEEDBACK.

1.4 3

~

1.2 r

g . . - -

b 1.

5 y .2 0

.6 g

8 a

w .4 i

3 -.

8 x .2 0.

5.

4.5

4. ,

o 3.5 '

E 3*

E a

2.5 2.

1.5 '

1.

0 .10 20 30 40 50 60 70 80 90 100-TIME' , (SEC)

BYRON /BRAIDWOOD STATIONS FIGURE 6 TUR8INE TRIP EVENT WITHOUT-PRESSURE CONTROL, MAXIMUM REACTIVITY FEEDBACK!

/

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

660 630 L

S 620 _-

e g 610 a

j w

600

$ 590 0 580 5

y.570

$ 560 v

550 540 600 .

C 590 8

e w 580 -

B E

5 g 570 O

560

.d Y

a

" 550 540 60 70 80 90 :100 0 10 20 30 40 - 50 TIME (SEC)

BYRON /8RAIDWOOD STATIONS

-FIGURE 7 ,

TURBINE TRIP EVENT WITHOUT ,

PRESSURE CONTROL, .. -

MAXIMUM REACTIVITY FEEDBACK 4

e . _ < u

2600.

-2500,-

_2 ._ _

f_ 2400.

u E 2300.

M u

a 2200.

5 N-E 2100.

8 0

g 2000.

1900.

1800.

1800.

@ 1600. -

5 1400.

d 0

g 1200.

=

0

-~

~

1000. -

E e

W

" 800, 600.

O. 10. 20. 30. 40. 50. 60. 70. 80.. 90. 100.

TIME (SEC)

BYR0sl/8RAIDW000 STATIONS FIGURE =8-TUR8INE TRIP EVENT WITH PRESSURE CONTROL, MAXIMUM REACTIVITY FEED 8ACK

1.4 -

~

J E 1.2 E . . - . _

g i.

5 C ~8 8

E_

, .6 W

2 4

g M

8 z .2 ,

k 0,

5.

4.5 4

o, 3.5 E

3' -

E O

2.5 -

2.

1.5 1.

0 to 20 30 40 50 60 70 to 90 100 TIME (SEC)

BYRON /BRAIDWOOD STATIONS FIGURE 9 TURBINE TRIP EVENT WITH PRESSURE CONTROL, MAXIMUM REACTIVITY FEEDBACK

e40 630

$ 620 . . . _

e u 610 j 600 e i 5 590 O 580 < j y 570 E 560 1 8

550 ,

i 540 l 600 1

C 590 S

e y 580 -

E s

$ 570 W

560

.h E

o

" 550 540 0 10 20 30 40 50 60 70 80 90 100 TIME (SEC)-

BYRON /BRAIDWOOD STATIONS FIGURE 10 TURBINE TRIP EVENT WITH PRESSURE CONTROL, HAXIMUM REACTIVITY FEEDBACK

.8600.

-2500.

. t. .Y' p- 2400. -

' ' ~

._ 'l u ,

B' 2300.

,u .Y..

A. 22 '.% 6 .

6 N

j.2100.

'N E 2000.

a. '

i 1900. -

, .1800.

4 i 1800.

..h 1600. "

1400.

8 E

y 1200. '

n N

~

E:-1000.

m w"

=

800.

4 600.

O. 10. 20. 30. 40. 50. 60. 70. 80. 90. - 100.

TIME (SEC) '

l BYRON /BRAIDWOOD STATIONS' FIGURE 11 I TURBINE TRIP EVENT WITH PRES $URE CONTROL, MININUM REACTIVITY FEEDBACK.

w

1.6

~

J E 1.2 , _ . _

s2 <

g 1.

5 g .5 G

~

, .6 w '

E

n. ,

, 4 6

d 3 .2 0.

5.

4.5 4.

o 3.5 E

a 3.

9 o

2.5 2.

1.5 1

1

1. 70 30 90 100 l 0 10 20 30 40 50 60 TIME (SEC)

.i l

BYRON /8RAIDWOOD STATIONS FIGURE 12 l i

TUR8INE TRIP EVENT WITH PRESSURE CONTROL.'

MINIMUM REACTIVITY FEED 8ACK

+ .

660  ;

630 6

8-. 620 _-

e u 610 5 I E 600 j E- i

$ 590 g 580 sw y 570 -

E 560 -

S 550 540 600 C 590

$ I e 1 w 580 E

E g 570 .

W ') I C

d 560 -

w i 8

-i 550  !

l 1

i' 540 0 to 20 30 40 50 60 70 80 90 100 TIME ~ (SED BYRON /BRAIDWOOD STATIONS  ;

FIGURE'13 TURBINE TRIP. EVENT WITH--  !

PRESSURE CONTROL,  !

NININUN REACTIVITY FEEDBACK ]

I

~1 i

i

. .c i

APPENDIX A OVERPRESSURE PROTECTION REPORT i

I i

i i

{'~ ]  ;

g- SAFETY VALVES i

T O PRE SSURIZ E R',

8

.--- --. __ _ -, pE,L,lEF VALVE OUTSIDE INSIDE I . . p4 "

l CONTAINMENT REttEF CONTAINMEN T

( ~~

~ REllEF u,,g syg,,

L ~"

,hh ,

?,, O VALVESs SAFE TY VALVES a

• SPR AY LINE

=4 h D- 7

' - ~ - - - - - - - ,

g X . .

k STEAM  ; '~} g GENERATOR 1 FROM 10 TUR81NE

' 4 PRESSURE O

CONTROLLER STE PR E SSURIZE R GENERATOR 2 SPRAY LINE $ '

LOOP 1 '

LOOP 2 I REACTOR REACTOR COOLANT COOLANT PUMP 1 PUMP 2 I REACTOR VESSEL STEAM ST E AM CENERATOR 4 GENERATCR 3 I t oo, . ' LOOP 3

- e P:No REACTOH REACTOR ---

INST RUMENT ATSON LINE COOLANT COOLANT PT PRESSURE TR AN$MIT TE R N"# 8 PUuP3 PC PRESSURE CONTROLLER LT LEVE L TRANSMITTER Figure 1 Schematic Arrangement Of Pressure Relieving Devices

h -- _#4 _ - 4 1 :ss:s 1 1

.. 3 5 2600 - ' l 2500 - .

2400 -

h 00 ,

e -

e 2 w

$ 21 e

3 2000

[1900 2700 g ,

5 2600 - I

• 2

2s00 -

e 3 2400 M

y 2300 0 2200 -

"i 3

2100 -

0 -

b *2000 C -1900

.f 1800 1.0

!_. 0.s -

u. >

_U "u

s w< .6 -

• k

' su

", 0.4 -

4-E e5 0.2 -

5 0

( l i I i 0 10 20 30 40 50 60 . j TIME (SEC) kg f 0.04- f LAN Figure 2.  ;

%_ kll mag i F/3are_. q

~

)

A I

S

(

P :3.

E  :: . .

R U O S

S E  ::. .

R P

R E

Z I

R U

S S .

E  :. .

R P

)

A I

S P

=: .

(

E =:.

R U

S S

E

=:. -

R P

T

=: .

E L

T U =.

O P

=.

C R

)

Y T

I .

C .

A P l, A

C i, F t, O

C  !,

A R  !, .

F

(  !,

E  !,

T A  !,

R F  !,

E I

L

, i  :

E 3 S .

R I V

S S

M g- N

j l

l

' i i

1250 4 l l l l[

M l

E -.

E

~

h115 f1100 b 1050 o

{ 1000 950 900 650 640 of 620 '

N g 600 -

8 m

580 -

M-560 -

~

1.2

/ \

z 1.0 o

0.8 Q

g 0.6 E

2 I -  :'

0.2 I l i l i l 0.0 l 0 10 20 30 40 50 60 j TIME (SEC)

E[ # E Figure 3 A &Ilow,'ng F,'yee .

" l; 1

. S. .

w- 1300.

.(0--1200.

h

'E l 5 1100. -l ,

w o 3

o 1000. ,

b 900. '

a C

• w 640 5

w 620 y 600 E

• $80 E

w '

I. 560 w

W

• m 540 u

et I

_i 7 .

~1 e

w o 1.2 -

, .6 >

$ .4 g

.2 -

C-0.

l 0 10' 20 30 40 50 60 70~ 80 90 100 TIME (SEC) u FIGURE 3

.l]

-i i

-,,eas A 2 6 n 6 A .m 9- A 'M APPENDIX B UFSAR MARKUPS s

e. m B/B-UFSAR TABLE 15.0-2 (Cont'd)

REACTOR VESSEL PRESSURIZER VESSEL AVERACE PRESSURIZER MATER FEEDWATER INITIAL NSSS TEMPERATURE e

TnERNAL power OUTrUT CooLawr TEMPERATURE PRESSURE VOLUME-FAULTS (Bett) FIDS (GPN) (*F) (PSIA) (ft 3) (*F) 15.1 Increase in Heat

. Removal by the Secondary System

- Feedwater System o and 3425 390,390 557 and 589.2 2250 450 and 1000 32 and 440 >

Malfunction Causing an Increase in Feed-water Flow 3425 390,390 589.2 2250 1990 440

• - Excessive Increase in l Secondary Steam Flow

- Accidental Depressurisa- 0 377,600 557 2250 450 50 tion of the Main Steam (Subcritical)

System O P7,600 557' 2250 450 50

-Steam System Piping .

Failure (Subcritical) 15.2 Decrease in Heat Removal by the Secondary System gyo j y73g.

- Loss of Enternal Elec- 3425 -390,390 5Asrf pe6 1090 440 trical Load and/or

~

Turbine Tr1p

- Loss of Non-Emergency 3579 377,600 565.5 2280 1150 442

-A-C Power to the Station Auxillaries 15.0-30 REVISION I - DECEMBER 1989

^ ^ - ~ ^ ' "~~' - * ..__w=' . _ _ _ _ _ _ _ , . ,

B/B-UFSAR TABLE 15.0-5

/

TRIP POINTS AND TIME DELAYS TO TRIP

- - ASSUMED IN ACCIDENT ANALYSES LIMITING TRIP POINT ASSUMED TIME DELAYS TRIP (SECONDS)

FUNCTION IN ANALYSIS 118% 0.5 Power range high neutron flux, high setting 35% 0.5 power range high neutron flux, low setting Variable see 8.0*

Overtemperature dT Figure 15.0-1 Variable see 8.0*

Overpower dT Figure 15.0-1 2.0 High pressurizer pressure jH((psig 1845 psig 2.0 Low pressurizer pressure 87% loop flow 1.0 Low reactor coolant flow

(

t .

(From loop flow detectors) 68% nominal 1.5 Undervoltage trip Not applicable 2.0 Turbine trip 13.7% of narrow range 2.0-Low-low steam generator level span level 87.4% of narrow range 2.5 High steam generator level span level trip of the feedwater pumps and closure of feedwater system valves, and turbine trip I

• 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 l f coolant loops exceeds the trip setpoint until the rods are l free to fall. l l

15.0-36

• ~ ~ m.

D Th

.- - OVERTEMPERATURE OT TRIP (INCLU INSTRUMENT ERRORS) AT IMOIC E SSURE S -

. O C

pp

% o US M CONmTMS WHERE NR F NORMNAL

---

OVERPOWER AT TRIP I

7 -2250 P$tA l 7 (h M __

l

( -----

2400 PSIA 3

? ~

1000 PSIA g

3 60 -

2006 PSIA g -

e_

C

$ W -

^

Locus of CONoti80NS \

g as o og wwRE oN.R - t NT roR i=PR ,

g O 3O THERe4AL DESIGN FLOW AT DE poi CHANNEL FACTORS g 2z 2 #

m >f, .o -

kC3 6 I M GENERATOR 30 $ o Locus of POINTS WHER SAFETY VALVES OPEN O

><mm $

3O ya pe 30 '

P-y 57 580 590 800 610 620 630 640 650' mm md AVERAGE TEMPERATURE (*F)

Oh Uk id$ a" 3

5 -

4

_ _ ___m __ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ __ _r __ _ _ _ _ _ _ _ _ _ _ = _ _ _ _ _ _ _ _ _ . _ _

\

h 0VERTDiFEAATURE AT TRIP $ i g

\  %

g 65-g g

~~- \

4 \ OVERP06fER AT TRIP

\

g g _\  ;

\

\ \ _,'- ,  ;

\ \  !

\ \

g 60- \

\ \

g \ \

g* \ \d

\ g g' 2460 PSIA

\

55-

\ g

\

i

\

\

\

\

h l l

\

\

g g Y g \

\ \

2250 PSIA

• 58< \

\

k g a g

1. I \

g i

. g \ \

\ g 45- M g \ s' TEM SDIERATOR '

S g s s SAFETY VALVES OPEN g

g \ \

g di \  !

\

\

b \

g 40< g \ \ .

\ l

\

\

2000 PSIA' i l 1860 PSIA g g

i \

g i g i i

55< g i

\ \

g s l

\ *  ;

g

\

g 005 LIMIT LINE3 I 50 - - -

g

\

\

~

\

.\ -

I 508 595 54 595 688 685 GIS 615 628 625 658 655 646 T evo fori F;3 v< e. . )5^ O - l

1

< 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 nd prevent DNB. Depending on the magnitude of he Icad l

inpu '

l loss, y saurizer' safety valves and/or steam genera r safety l

valves ma be required to open to maintain syst ressure:telow allowable 1 its. No single active failure wi 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 Radiolacie Consecuences Loss of external load fr full po r would result in the operation of the steam dump ys .- This system keeps the ma in turbine generator operating t upply auxiliary electrical <

loads. Operation of the at p system results-in bypassing l steam to the condenser. steam umps are not available, steam ieve to the atmosphere.

generator safety and re of valves his transient the Since no fuel damage postulated for radiological releas , given in Table 1 . -4, will be less se vere than those for t steamline break accidentser.clyzed in 5ubsection 15. .3.

L5.2.2.4 nelusions lased - results obtained for the turbine trip event ubsection

.1, t ae

.L5.2 ) and considerations described lbs Subsection 15.2.

t .i icable acceptance criteria for a loss of external loa ve st t _ ,

15.2.3 Turbina Trin 8 15.2.3.1 Identification of causes and Accident Demerintion For a turbine trip, event, the turbine stop valves close rapidly (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. Iow bearing oil pressure, I

c. turbine thrust bearing failure, l

d. turbine overspeed,

e. DEH d-c power failure, and

f. manual trip.

Upon initiation of stop valve closure, steam flow to the turbine u stops abruptly. Sensors on the stop valves detect the turbine u '

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

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

15.2-4  !

l I

,__ ., __ _ m .. . - . . . - ._ _ ._ _ _ _ _ _ , _

~

i

.8/B-UFSAR pressure.with a: resultant primary system transient as described For in Subsection 15.2.2.1' for the loss of. external: load event.

(.- .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% H power on the. units where~the P-8 modification has not been i implemented) on a signal from the turbine auto stop oil. pressure 1 or the turbine stop valves..

The automatic steam dump system'would'normally accommodate / thel excess steam generation. Reactor coolant temperatures.and pres- i 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 For to the this atmosphere situation, and_ main feedwater. flow feedwater would be flow would be lost.

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'See generator safety valves 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 offexternaliload, As such,. floss I, of condenser vacuum,.and other turbine ~ trip' events.

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-SubsectionL15.0.8 and.

listed in Table 15.0-7.

15.2.3.2 Annivnia of Effects una conneauenean 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 to'The'reactorfis not tripped >

demonstrate core protection margins.- 'No'creditlis'taken until conditions in the RCS result in a trip.

for steam dump'.- Main : f eedwater. flowl is ' terminated' at thel time: of

-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 detailed digital computer program LOFTRAM (Reference 3).- The' i program simulates the neutron kinetics, RCS pressurizar, 1 pressurizer relief and safety valves, pressurizar spray, The' program steam '

generator, and steam generator' safety valves.

(

15.2-5

B/B-UFSAR computes pertinent plant variables including temperatures, pressures, and power level.

This accident is analyzed with the improved thermal design procedures as described in WCAp-8567. Plant characteristics and initial conditions are discussed.in Subsection 15.0.3. l Major assumptions are summarized below:

a. Initial Ooeratino conditions - initial reactor power,  ;

pressure, and RCS temperatures are assumed to be at their nominal values. Uncertainties in initial conditions are included in the limit DNBR as described in WCAP-8567.

b. Moderator and Donoler Coefficients of Reactivity -

the turbine trip is analyzed with both maximum and minimum reactivity feedback. The maximum feedback cases assume a large negative moderator temperature coefficient and the most negative Doppler power coefficient. The minimum feedback cases assume a least negative moderator temperature coefficient and the least negative Doppler coefficients. (See Figure 15.0-3.)

c.

Reactor control - from the standpoint of the maximum pressures attained it is conservativeIftothe assume that reactor i the reactor is in manual control.

were in automatic control, the control rod banks would move prior to trip the reduce and severity of the transient,

d. Steam Release - 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 setpoiny where steam release through safety valve limits Acondary steam pressure at the setpoint value. j

e. Elgssurizer Sorav and Power-Ocerated Relief Valvesi -  !

two cases for both the minimum and maximum reactiv'ty feedback cases are analyzed:

1. Full credit is taken for the effect of pressurizer 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.

Safety valves are operable.

15.2-6

o B/B-UFSAR-

.l l

f. Feedwater Flow - main feedwater flow to the steam

~ generatorssis assumed to_be lost:st the time of

-A '

turbine trip. No. credit is takenJfor auxiliary feedwater flow since-a stabilized. Plant: condition will be reached before' auxiliary feedwater. initiation

< is normally_ assumed to occur.- Thexauxiliary. feed-water flow would removeLeore decay heat following plant stabilization,

g. Reactor Trin - is actuated by;the first reactor, protection system trip setpoint reached. Trip j signals are expected due to high pressurizer- l pressure,_overtemperature AT,-high pressurizer 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 pressurizer sprayLand 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. Pressurizer safety _ valves'and/or steam l generator safety valves may be required to openJtoTmaintain 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 12.- ,

1

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

reactivity feedback and two' cases for maximum. reactivity-feedback:

' - i ~

b- (Figures 15.2-1 through 15.2-8). The calculated sequence of

'T events'for the accident is'shown in.TableL15.2-lj T Figures 15.2-1 and 15.2-2 show the transient! responses'for the if total loss of steam load with~a least negative' moderator tem-g erature coefficient assuming full credit for.the pressurizer; k pray and pressuriser power-operated. relief valves. No credit is4 I, aken for the steam dump. The reactor _is-tripped by'the h414e I , :::::i::: ;;;;;;;; trip. channel. The minimum DNSR'rgmains well'

,g above the' limit value. 'The pressuriser ' ;;f;;y ;;1.e; ire . . .

actuated and the. primary system. pressure remains-below the'110%

design value. The steam generator safety-valves 111mit the g.

w t; ;;;;;;ti;; ;t ti: ::f-' :17:

• secondary steam ;;;0itien 6 .. Petstwee. b less - %en (10 % of-fbe. [e'6 s'y ya lu e .

Figures 15.2-3 and 15.2-4'show the response forftheLtotal loss of' steam load withia large-negative ~ moderator! temperature coeffi-cient. All other plant _ parameters areSthe same as the above. .

The DNBR increases throughout the transientiend naverLdrops below its initial value. Pressurizer relief valvestand steam generator l ~: ,

peec-oprehJ rel.'th va bc.5 i

e _ r _ c w. - --, _ . _ _ - . _ . _ _ _ _ _ _ _ . _ _ _ _ _ . _ _ - ,

-B/B-UFSAR Y safety valves prevent overpressurization in primary!and ' secondary .

LL -systems, respectively. The pressuriser safety valves are not. l actuated for this case.

In the event that- feedwater flow is not terminated at the timum of

-turbine trip for this case, flow would continue under automatic control with the reactor atia reduced power. The operator would take action to terminate the transient and bring the plant tona stabilised condition. If no action were taken by-the operator the reduced power. operation would continue until thelcondenser hotwell was emptieg. A low-low steam generator water-level reactor trip would generated:along with auxiliary feedwater initiation signals. iliary feedwater would then be used to~

remove decay heat with t suits less severe than those presented in Subsection 15.2. .

even+v ,lly The turbine trip accident was also studied assuming'the plant to 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 fluz_ remains essentially constant at full power until the reactor is tripped. The DNBR i;;;;;;;;

sh...,L..L the trea;iest ;;0 never drops below it( initial value. In this case the pressuriser safety valves-are' actuated, 4 and maintain system pressure below 110%'of the. design value.

Figures 15.2-7 and 15.2-8 are the transients with maximum reactivity feedback with the other-assumptions being!the same as.

in the preceding case. Again, the DN8R increases'throughout the ,

transient and the pressuriser safety valves:are. actuated.toLlimit 1' 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 Radiological consequences The turbine trip transient and steam released for.this event are similar to the loss of load transient described in Subsection- 1 15.2.2.3.

There are only minimal radiological consequences associated with this event, thereforei this event is not limiting. The radio-logical consequences resulting from atmosphere steam dump are less severe than the steamline-break event analysed'in Subsection

15.1.5.3 since no fuel damage is postulated to occur.

(

15.2-8 REVISION 1 - DECENSER 1989 l

B/B-UFSAR 15.2.3.4 Conclusions

\ Results'6f~the analyses, including those in Reference 1, show that the plant 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 NSSS to safely withstand a full 1 load rejection. The radiological consequences in this event will be less than the steam break event analyzed in Subsection 15.1.5.3. ,

l i

I '.2.4 Inadvetient Clusute of hain steam 1501at10n Valves I Ina rtent closure of the main steam isolation valves wo d I n a turbine trip. Turbine trips are discussed l result Eubsecti n 15.2.3.

Los of Condenser Vacuum and Other Events musino a l 15.2.5 i Tu r bi'he Tr i o Loss of condenser vacuum is one of the event s are that can cause a  !

t urbine trip. Tur e trip initiating eve described in l Subsection 15.2.3. loss of condenser v cuum would preclude the one of steam dump to t condenser; how er, since steam dump is a saumed not to be availa e in the tu ine trip analysis, no i a dditional adverse effects ould re it if the turbine trip we re c:aused by loss of condenser cuu Therefore, the analysis- i results and conclusion contain ition, analyses15.2.3 n Subsection for apply tc the other l

J oss of condenser vacuum. In siossible causes of a turbine ection rip, as listed in Subsection J 5.2.3.1 are covered by Su .2.3. Possible over-f requency effects due to turbine ov speed condition are d,iscussed in Subsectio A5.2.2.1 and er not a concern for thi s t ype of event.

2 5.2.6 Loss of M emeroency AC Power to the lant Aurillaries lention of causes_and Acciden serietion

] 5.2.6.1 Iden A complete oss of nonemergency ac power may result the los s f all po er to the plant auxiliaries, i.e., the renc r coola nt c

I umps, ndensate pumps, etc.- The loss of power may be aused by 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 tribution system.

• 15.2-9

4 B/B-UFSAR' TABLE 15.2-1 TIME SEOUENCE OF EVENTS FOR INCIDENTS WHICM CAUSE A ,

DECREASE IN M2AT REMOVAL BY THE SECONDARY SYSTEM  ;

TIME ACCIDENT 233][I (see)

Turbine Trip

1. .W ith pressurizer Turbine trip, 0.0 control (minimum loss of main feedwater  ;

reactivity feedback) flow m ,

O**N*"f hbt AT, :::c. ;;;;;; i;;: ;;;; 7.<tr

+ese reactor tr i p po i nt g,9 reached . l Initiation of steam

• f<5' release from steam g,f generator safety valves ,

Rods begin to drop JAf

+ . f.1 "

Peak pressurizer pres- 10.5 sure occurs (1)-

Minimum DNBR occurs' .%

/$. 0  ;

(1) Primary pressure is measured at the pressurizer in the-plant. Although the peak pressure in the RCS is slightly-higher than the pressurizer pressure, pressurizer pressure is reported for transients that do not challenge RCS integrity. l For transients which challenge RCS integrity, peak'RCS: 1 pressure is reported.- For all transients, it is ensured that. d peak RCS pressure remains below 2750 psia.- -l i

O 4 6w6 Y 4 4 ww e WW &

w w www sww a 1

.j I

15.2-25 4

- ~ n m a n- s - ,'

j B/B-UFSAR TABLE 15.2-1 (Cont'd)

TIME ACCIDENT EVENT (sec)

2. With pressurizer Turbine trip, 0.0 control (maximum loss of main feedwater reactivity feedback) flow Initiation of steam Jpdf release from steam g,3r generator safety valves Peak pressurizer St(

pressure occurs 7. 5"-

ps" Ove r4e mp era.bec. AT" re:-1 : et::r ::.:r:ter reactor trip point 7, y reached -

Rods begin to drop (

Minimum DNBR occurs (1)

Without pressurizer Turbine trip', 0.0 3.

control (minimum loss of main feedwater reactivity feedback) flow l High pressurizer pressure feC" reactor trip point y,3 reached Rods begin to drop psf 63 Peak pressurizer pressure f occurs )<J[

?,

~

Initiation of steam $df

_. release from steam 6.5~

,enerator g safety valves Minimum DNBR occurs (1)

Turbine trip, 0.0

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

High pressurizer pressure k:17 reactor trip point 4,3 l reached  ;

I DNBR does not decrease below its initial value.

(1) 15.2-26 l

I

'B/B-UFSAR  ;

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

. TIME  ;

ACCIDENT EEI3I (sec)

. Rods begin to drop M6. 3 '

i Peak pressuriser pressure M occurs 7, O Initiation of steam J.af release from steam g, , g -

~

generator safety valves ]

l Minimum DNBR occurs (1) .

b == cf =cee--r; m "-in ft:fr:t : fi;r 1" a, ower stops Low-low steam generator 52 water level' trip. -

Rods begin to drop' 54 Reactor coolant pum 54 begin to'coastdown l

Four_ steam gene tors 11 begin to recei auxiliary fe water from one motor o von auxiliary- -'

sedwater ump' Co a liary feedwater 259  :

is d vered to the sta nerators-k'wate ' level in 310 ressuriser ecurs Core decay hea decreases -32!

to auxiliary f stor heat removal caps ty ,

Lc.ss of Normal Fe - Main feedwater flow 10 ~

l i water Flow stops Low-low steam generator 52 '

water level trip Rods begin to drop 5 15.2-27 REVISION 1 - DECEMBER.1989 ,

t

, - - - . ~. . ..

B/B-UFSAR t

TABLE 15.2-1 (Cont'd)

TIME ACCIDENT EVENT (naei Peak water level in 113 l-pressurizer occurs (1) DNBR does not decrease below its initial value.

( i i

15.2-27a REVISION 1 - DECEMBER 1989.

- 1.2 -

c* 9

( gE 0.s -

k,

=8 2za 0.6 -

io h 0.4 -

o

=Wcc 0.2 -

5 L 0

• 2s00 1 /

g 2500 -

h 2400 E

a- q 2300 ea g s 2200 -

e g 2100 -

E 2000 - 1 1900 X 1500 1400 jg1200

$ [ 1200

$ ! 1100 -

c' E $ 1000 -

1 I i 1 I I l 0 25 50 75 100 125 150 175 200 TIME (SECONDS)

BYRON /BRAIDWOOD STATIONS g5.// AC E "/ / TN UPDATED FINAL SAFETY ANALYSIS REPORT fAc 4//ou,'ng FicuRE 1s.21 TURBINE TRIP EVENT WITH PRESSURIZER SPRAY AND POWER OPERATED RELIEF VALVES, b's.y u re.S MINNUM REACTIVITY FEEDBACK

l l

l l

1 l

O' R

W E

~

o R

R r 2  ;

W N e e e q g ,

• e e e . . o e ==

(7bN! WON JO N011305Ji 53A0d au]73nN F.'yce 15 2-I

/ ,

/d3

em'FM S

a a.

so 5

C m

S w

. E o ~~W 4

a' N

O c o O O o o O o o a a . .

N N ISISdl 33nSS33d 33Z130$$33d i

l F.' y a IS. 2 -l  :

I

$0 .

9

I I

gM*Y Y O

O w

. 4 O

O A

D

=

C4

. w O >

c W

. E:

O b v

O m

O

~

e 9 58 O'

N $

- k - -

'SAJI 3Hn30^ 33Ltin 53Zl3nss3ng

/5'.z-/

A3 %

Tof .F

' ~

_~a. _ . , . _  !

i

\, C 590  !

l 580 -

gj570 2

560 1

550 640 i

l g oI 620 -

Ee i

! e$ ** l m

E a.

8 -3 580 -

560 5.0 4.5 -

4.0 -

1 y 3.5 -

O 3.0 j

2. -

.0  ! i 0' 25 50 75 100 125 150 175 TIME (SECONDS) aYRON/BRAIDWOOD STATIONS

[EPLACE W/TH UPDATED FINAL SAFETY ANALYSIS REPORT -

b b 8 *' FOURE 15.2 2 hs's gg $ TURBINE TRIP EVENT WITH PRESSURIZER SPRAY U AND POWER-OPERATED REUEF VALVES, MINIMUM REACTMTY FEEDBACK 1

'I

-- u A 0

0 R

S O I E 3 I R

R S

O 4

r .n . . . . .

(J D301 3bO1WB3dW31 137N1 3803 R)v4 /52-2 lof 3 1

l l

l g@+ MF 8'

l

\

o I l

o E

O u.

O E

S I E

2 2

• \

o o o o o o o o o o o

• m ~ ~ o e e n e e a e * * *

• e e e. e e e l

iJ D301 3an1053dW31 3 DUB 3AU 3803 l

F:y<< l 5'. 2 -2 i

f0

4 I

I 5.

4.5 o

C w  ; '-

O o 3.5 N C W .9 E 3'

N @

i y z.5 z.

1.5 1.

0 10 20 30 40 50 60 70 80 90 100 TIME (SEC) g

n 1.2 I I l l I I I i 1. .v

' mE <

• 3 0.8 .

$E e$ 0.6 -

f

$5

/

g; q

0.4 -

,./

5 0.2 - /

% ./

~

0 /

2600 ,

25m - .e u

24m g ,

g 2300 ,

'2 s e a 2200 - ,

es E 2100 -

f

~i 3 '

i B 2000 --

e S

1900 -

1800 5 1500 r

ja 1400 -

5 13 "

h ! 1200 -

c

. a s' 11 -

E1 0 I

25 I

50 75 I I 100 125 I I 150 I

175 2 TIME (SECONDS)

BYRON /8RAIDWOOD STATIONS g6/7 Ad.6 W /TJ/ UPDATED FINAL SAFETY ANALYSIS REPORT FIGURE 15.2 3 g f ((,sik7 TURBINE TRIP EVENT WTTH PRESSURIZER SPRAY AND POWER OPERATED RELIEF VALVES,

^

gj b MA)0 MUM REACTMTY FEEDBACK j

4 em

• e O

O w c

so N

E C w

w a

w b

3*

a  !

o N

I J

" l 1

o 4 e

• e' O. N. a

• = e-170NIHON JO NOI13u3J) 43A0d BU313nN l

F,'3 v - <. / s 7_ - 3 l

l

/ o+ 3 1

I l

1 1

1 l

i 1

o 1 o

o )

Om e

o l ao l l

.1 4

o N

o **

4 W'

w w

. ~

o e

w o,, C o

n o

N e .

o N o o o o o o o o o o a o o o o o o o e e # m N - o o. o.

N N N N N N N s'* e ItslSdl 3 BOSS 33d 33ZlBOSS35d i

RA S / 5 2. - 3 1

l 2.f 3

4 l

1 I

1 O

e e i O

P 4

O se e

O N

e O '

4 m W

W t/3 e w O

e W

e E O

< P O

M e

O N

O I

e O 1 e e

• f O O O O 1 O O O O n e ,0 4 e l

• *  % ,N l

EI133 M T A 3310A 332lBOS$3$d i

F:3m I s'. 2 - 3 3,&3

1 I I I I I I s ,C 590-

, k .

]g580 -

N -

X /r' m< s.

\

g g 570 -

u.a -

N /

$ 560 .e

/

550 4

640 / .

/ \

go 620 -

<m -

55 Ej ' [ , '/

Et s

@ g M0 - e

~ / -

560 5.0 4.5 - .

4.0 - .l g 3.5 - ]

b 3.0 -

2.5 2.0 l l l I I I I i

/,J 0 25 50 75 100 TIME (SECONDS) 125 150 175 2.1 I

I BYRON /BRAIDWOOD STATIONS' g g4 g g. ggg UPDATED FINAL SAFETY ANALYSIS REPORT

, FIGURE 15.2 4

? Y h f$0 turn $v TURBINE TRIP EVENT WITH PRESSURIZER SPRAY AND POWER-OPERATED RELIEF VALVES, y gvce5 MAXIMUM REACTIVITY FEEDBACK i

l I

' l

M 5

i

=

=C O

=

e s

IJ 9301 3an1053dW31 13%I 3303 F:yce. 1 5 2 'I lJ3

4m" O-M h

a R

S-M S

3 E

g C-3 2

3 O

4 IJ D30) 33ntun3du31 30yy3Au 3yg3 F.'yr I S' 2- 4 2#3  ;

i

5.

4.5 y

wC 4 d

e 3.5 w ' E

=

o  %

p 3.

N o 1 2.5 4

2.

1.5 1.

0 10 20 30 40 50 60 70 100 TlHE (SEC)

~

l 1.2 1 l l l l -l l l 3 1.0

/ Z e{

y 0.8 - -

22 0.6 - ,

U$ '

y ;:: 0.4 -

2N E 0.2 - ,

~

k j 0

F 2600 ,

25m D

$ 2400 E

E q 2300 e

E $ 2200 -

/

E '

y 2100 - .

w 2w0 f E 1900 1400

$ 1300 .

1200 m-yW 1100 E"

D 1000 '

e w0

' l- l l I I I I I l

75 100 125 150 175 200 0 25 50  !

TIME (SECONDS)

BYRON /BRAIDWOOD STATIONS-UPDATED FINAL SAFETY ANALYSIS REPORT fa l'r./RE MITH FIGURE 15.2-5

/ ,i

[ TURBINE TRIP EVENT WITHOUT PRESSURIZER -

SPRAY AND POWER OPERATED RELIEF VALVES, i

MINIMUM REAC11VITY FEETSACK

, p v -t S

. -)

a -

Q s Q-W 9

M t'!

~

3 E '

op '

3 i

1 o '

• j F

f o

• N 4 .

• f N. a  ;

" ,=

(10N! WON JD N01100aJ) BJA0d aW373AN l

Re-<. /r. z- s-

/o63 I

r- v--

4 1

I l

O O

o O

eo \

4 O

N

\

)

O p Q

( un

.. th o

f

\

g O Y '

4 \

(

\

O .\

A

. \

N

\

O \

e= 3 o

o o o o o o o

o o o o o o- o l e e oe m o I N N N N w o o.

a o.o  ;

N N N N w w -

tutsdi 3anss3ad a3ztanssaad l i

l 1

P%3 /S. 2. -r L af 3

.- e , - - - -

1 l

I 1

l l

1 o

d 5

Y G m

e m

. E O

w h O

m O

N e

O-

• e .

O O O O Q Q O O O O O O O

• O

• • $ e (S1JI 3Hn10A 3310A 33ZlBOSS35d 4

F.3 v ( /S.2-F 3J3

% I I I I I I i

/

/

.C 590 580 ..

j l r  ;

510 ,i lE -'

560 4

550 640

/

g [ 620 -

I!

tw 8h580 50 '

5.0 .-

~

4.5 f 4.0 /

/

3.5 ,

cr:

@ 3.0 ,

a 2.5 2.0 1.5 I I I I I I I 50 75 100 125 150 175 200 O 25 TIME (SECONDS)

BYRON /BRAIDWOOD STATIONS UPDATED FINAL SAFETY ANALYSIS. REPORT -

FIGURE 15.24

[ TURBINE TRIP EVENT WITHOUT PRESSURIZER SPRAY AND POWER OPERATED RELIEF VALVES..

uiNiuuu REacTmTY FEEDarex F.'3 vre.3

600 T,

5 O 0 O

g 580

' 3 G

N i 570 m

D "

t O

560

.d W

O u

550 -

540 0 10 20 30 40 50 60 70 80 90 100 TIME (SEC) m l

l

A.

9 O O

~

R S-M C

3 E

? I 3

2 O

M N

- - - --e e e $. e. h.

IJ 9301 3801033dW31 3DU33AW 3303 Rp,e IS 2-6 2 63

---

JiiiMD-----  ;

5.

4.5 u-1 4.

1. I W '

s o 3.5 O

N- E y N

=

m 3-t 5 e 2.5 2.

1.5 1.

0 10 20 30 40 50 60 70 80 90 100 TIME (SEC) g

l l l l l l l

- l C 1.0

<~

EE

~f. 0.8 g -_ _

a. '

_ m$ 0.5 -

t u8 '

/

g- 0.4 -

ZN l c g 0.2

-t /

0 1

2600

\ ,

/

2500 - ./

3 2400 - -

/

8 E 2300 -

eg .

$ 2200 t:!.g

/ i e 2100 - /

h w 2000 - ,

m /

( "

1900 -

,/

1800 1400 ,

E Qg 1300 j

'/

E [ 1200 m-y y 1100 -

,, /

mo e f 1000 - j'

/

E>

a.

900 m-I I I I I I I L 50 75 100 125 150 175 20

/0 25 TIME (SECONDS)

BYRON /BRAIDWOOD STATIONS UPDATED FINAL SAFETY ANALYSIS REPORT k E WM FIGURE 15.2-7

% c_ kllowaby TURBINE TRIP EVENT WITHOUT PRESSURIZER e SPRAY AND POWER OPERATED RELIEF VALVES, Fia reS MAXIMUM REACTMTY FEED 8ACK

, _ _ _ _.. _ . _ . . . . i

.-l . . . . . . .--

l 8

S E

R 8-M e

E E

~

3 R

2 3

l l

• N 9

~

9 , o

(*1bHIHON JO N011308J3 83A04 au313ON p;3 ves /T.2-1 i

/of 3

b k

k C

u S

l .E SP d

d a d .a a a d a a 3 8 3- R R S N

8 N

8 e=

e=

N N N N N 1015d1 380SS3ad 33ZlanSS3ad F:y.<. /5 2-7

2. of 3

w get- Y PO I

S d

d 5

$a I

M

.E o-4 W d

5 a

a a a a a a a -

3 3

3 3

8 3 3 IS1Ji Jun10A B310A B3ZlanS$3Bd F.3 v%

/r. 2 - 7 T of]

J

.g

4 % d - 4 ,c- - - as -ea4 l l l. l l j l

~

~,-, .. ._

~~

E 5. 570 8t'a .i

• 560

.'f 550 640 , 'f -

g '

g *_ 620 -

ee '

[{soo w$

es 8 3 580 -

( 5.0 j 4.5 -

4.0 -

x <*

8 3.5 -

3.0 2.5 I I I I I l 0 25 50 75 100 125 150 175 2 TIME (SECONDS)  ;

i BYRON /BRAIDWOOD STATIONS )

UPDATED FINAL SAFETY ANALYSIS REPORT  !

kE PLM.e WITH FM3URE 15.24

/

M ' h fl0ul/n i T TURSINE TRIP EVENT WITHOUT PRESSURIZER SPRAY AND POWER OPERATED RELIEF VALVES,-

p'*4 *c 5 uAxmuu RE4cTmTy FEEDS 4cx g

.. m .

. -w e-S-

M 5

I, 3 3

E

~

R 2

a e

!J D301 33n1033dW31 13*1NI 3303 Rya IS.2-8 l

l 640 630 a

S 620

~n 9 d, u 610 E 600 N

0 5

$ 590

/

$ s -

N hl 580 W N $ 570 g

0 560 550 540 0 10 20 30 40 50 60 70 80 90 100 TIME (SEC)

o 2

o 5 0'

o.

EO w

W o

W W

5 3*

o N

o l e .

d " .;

• A ~

m a OlLUU SNQ F.y- / r. 2. - e 3 J .3

7- , -:-

.)

l 1

e APPENDIX C SIGNIFICANT HAZARDS EVALUATION i p

4 9

SIGNIFICANT HAZARDS EVALUATION

.. 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 propos'd amendment would not: 1) involve a significant increase in the probdility or consequences of an accident previously evaluated, or 2) create the possibility of a new or different kind of accident from any accident previously evaluated, or U involve a significant reduction in a margin of safety.

DESCRIPTION OF AMENDMENT RE0 VEST:

The purpose of this amendment requast is to revise Technical Specification Section 3/4.7 to relax the main steam safety valve (MSSV) lift setpoint tolerance from 1% to 3%. 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 result, the plant is placed in an ACTION statement and must take immediate steps to avoid a violation.

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 (NB-7512.1). This 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.

BASIS FOR NO SIGNIFICANT HAZARDS DETERMINATION:

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 proposed change.

i The effect of a increase in the allowable Main Steam Safety Valveg7W 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 asspaing the current MSSV Technical Specification set pressures plus the propdsd additional 3% uncertainty. The calculated peak cladding temperatures were well below the 10CFR50.46 22000F limit.

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 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 inside containment.

The proposed change has been evaluated in accordance with the Significant Hazards criteria of 10CFR50.92. The results of the evaluation demonstrate that the change does not involve any significant hazards as described below.

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

Relaxation of the MSSV setpoint tolerance from 1% to 13% 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 the consequences of an accident.

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

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.

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

The margin of safety as 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, I RCS pressure boundary, and containment integrity continue to be met.  ;

l

. . . . .. .. .. - . . .. .. . . ~ . . ..

l k

APPENDIX D MARKED UP TECHNICAL SPECIFICATION SECTIONS I

G e

v . , , , .m

c l'

.. i TABLE 3.7-2_

I

. _ - STEAM LINE SAF~*Y VALVES PER LOOP V_ALVE NUMBER 3 )

LIFT SETTING (::n)= di cRI,!CE' SIZE M5013(A-01  :

1235 psig 16 in2 MS014(A-0) 1220 psig 16 in2 M5015(A-0) 1205 psi 9

.16-in2

~M5016(A-0) 1190 psig 16 inz MS017(A-0) 1175 psig ,

16 in2 "The lift setting pressure shall correspond to ambient conditions o valve at nominal operating temperature and pressure '

s: p,n ksjerj va}ves skll be SeY So 't I Eo

!6/*^ CF -

a f

L e

4 F

b L

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

4 e e

- - - . -_ _ . _ _ _ _______m_ _ -______

p ,

j h

=

s

, , , _ , . . TABLE 3.7-2 L

STEAM LINE SAFETY VALVES PER LOOP l 3,

VALVE NUMBER LIFT SETTING (2 3 )* F ORIFICE SI.i MS013(A-D) 1235 psig 16 in2 MS014(A-D)- 1220 psig 16 in2 M5015(A-D) 1205 psig 16 in MS016(A-0) 1190 psig 16 in M5017(A-0) 1175 psig  ;

16 in2.

"The lift setting pressure shall correspond to ambient conditions of the -

valve at nominal operating temperature and pressure..

• ALL Te5Ted VMs(5 5HM.L 6t. stT to t I % foinact.,

(

l 1

l J

'I BRAIDWOOD - UNITS 1 & 2 3/4 7-3

. l 3/4.7 PLANT SYSTEMS-BASES-

-l

'l 3/4.7.1 TURBINE-CYCLE 3/4.7.1.1 SAFETY VALVES-The OPERABILITY'of the main steam line Code safety valves ensures that

- the Secondary Coolant System pressure will be limited to within 110% (1320 psia)-

of its design pressure of 1200 psia during the most severe anticipat'ed system operational transient. .. The maximum relieving capacity is associated. with a tureine trip from 102% RATED THERMAL POWER coincident with an assumed loss of .)

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

/ AM 'IVSERT' Texr Aste..

Thespecifiedvp1ve".Tiftsettings-andrelievingcapacitiesarein ,

accordance with the requirements of Section III of the ASME. Boiler and Pressure- a Code,1971 Edition.S/The total relieving capacity for all valves on all of - l the steam lines is 17.958 x 10' lbs/h which is 1195 of the total secondary' steam flow of 15.135 x 10' lbs/h at 100% RATED THERMAL POWER. A. minimum of .

two OPERABLE safety valves per. steam generator ensures- that sufficient -

relieving capacity-is available for the allowable THERMAL POWER restriction:

in Table 3.7-1.

I STARTUP and/or POWER OPERATION is allowable'with safety valves inoce~rabl'e within the limitations of the ACTION requirements on the basis-of the reduction

~

- in Secondary Coolant System steam flow and' THERMAL POWER required b9 the reduced Reactor trip-settings of the Power Range. Neutron Flux channels. The' Reactor Trip Satpoint reductions are derived on the following bases:

For four loop operation:

" IU SP =

X x (109). ,

l Where:

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

l V = Maximum number of inoperable' safety valves per steam line, l H

l BYRON - UNITS 1 & 2 B 3/4 7-1

m -

3/4.7 PLANT SYSTEMS BASES 3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES The OPERABILITY of the main steam line Code safety valves ensures that-the Secondary Coolant System pressure will be limited to within 110%'(1320 psia)L of its design pressure of 1200 psia during the most severe anticipated system operational transient. The maximum relieving capacity is associated with a turbine trip from 102% RATED THERMAL POWER coincident with an assumed loss o_f condenser heat sink (i.e.,'no steam dumps to the condenser).

7 yA 7.45stt" *iEY VfR6 l The specified sfalve lift settings and relieving capacities are in -

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 the steam lines is 17.958 x 10' lbs/h which is 119% of the total secondary s

steam flow of 15.135 x lo 1bs/h at 100% RATED THERMAL POWER. A minimum of two OPERABLE 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 in Secondary Coolant System steam flow and THERMAL POWER required by the reduced Reactor trip settings of the Power Range Neutron Flux channels. The Reactor Trip Setpoint reductions are derived on the:following bases:

For four loop operation:

~I ) x (109).

SP = X Where:

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

l

l BRAIDWOOD - UNITS 1 & 2 B 3/4 7-1 .)

u ,

i i

1

. Insert.

The Technical Specification requirement that Steam'Line 'i Safety-Valves be set to within 1% 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 with setpoint tolerances?to within ,

3% is supported by " commonwealth Edison Company, Byron &

Braidwood Stations Units 1 & 2 Overpressure Protection Report."

P f

P I

e e

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

SARGENT & LUNDY ENGINE E RS F O U N D E D 18 91 sd CAST MOwmOC STHJET CHICAGO, ILLINOIS 60603

( 312 ) 289-2000 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 11%. 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 -3% does not affect the results of our previous analysis. The Main Steam system piping analysis and 1 Auxiliary Feedwater system capacity design basis is not'affected I by a change in the negative tolerance. It should be noted j however, that an increase in negative tolerance increases the potential for spurious valve openings.

If you have any questions concerning this matter, please feel j free to contact either Mr. J. R. Meister at 312-269-6882 or me at 1 312-269-6708. )

I

r -

1 CARGENT Q LUNDY ENCINEEMO CHICACS Mr. R. E. Waninski October 4, 1990 Commonwealth Edison Company Page 2 I

Yours very truly,

• , f J. G. Saltarelli Senior Mechanical Project Engineer JGS:cl Copies:

F. G. Lentine K. L. Kofron R. Pleniewicz E. R. Wendorf 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

SAltGENT & LUNDY ENGINEERS rouwCEO isei SS EAST MONROE STRECT CHICAOO. ILLINOIS 0603 (3ftlee9+aOOO 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 Commonwealth Edison Company Nuclear Engineering Department 1400 Opus Place, Suite 400 Downers Grove, Illinois 60515

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, '/2MS016A-D, 1/2MS017A-D) setpoint tolerance as referenced in my June 25, 1990 letter to you. The current system design is based on the setpoint tolerance of 1% 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 psla g 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 scenarios. In accordance with your request, AF system capacity was evaluated for the feedwater pipe rupture and loss of main I feedwater (station blackout) accident scenarios at an unfaulted steam generator pressure of 1250 psia. The scenario results are summarized as follows:

l Feedwater Pine Ruoture l l

. Three intact steam generators at 1250 psia

. One faulted steam generator at 14.7 psia 1

. One AF pump (motor driven) operating  !

- Resulting AF system flow to three intact steam generators I is 458 gpm l

CARGENT O LUNDY ENGINEEAD C MICA 30 Mr. R. E. Waninski August 17, 1990 Commonwealth Edison Company Page 2 Loss of Main Feedwater/ Station Blackout

. Pour intact steam generators at 1250 psia

. One AF pump (diesel driven) operating

. Resulting AF system flow to four intact steam generators is 763 gpm The following listing summarizes the basis and assumptions utilized in the Auxiliary Feedwater system capacity evaluation:

. 1/2AF005A-H valves in full open position

. AF pump performance per vendor manual curves

. Condensate Storage Tank empty, water Elevation 399'-9" for Braidwood Station was utilized for conservatism

. Suction piping friction losses for Braidwood 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 faulted steam generr .or water level of Elevation 439'-0",;which corresponus 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 gpm was assumed. i l

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 affected by the increased )

setpoint tolerance, l

l 1

l

.- ~ . . . .

n

SARGENT Q LUNDY ' 'I EN01NEEMO.

CMicAso Mr. R. E. Waninski August 17, 1990 Commonwealth Edison Company-Page 3 If you have any questions concerning this matter or require any additional flow' scenario evaluations, please feel.. free to contact either Mr. J. R. Meister at 312-269-6882 or.me at 312-269-6708.

Yours very truly, j.4.lb e J. G.'Saltarelli-Senior Mechanical Project Engineer JGS:cl Copies:

F.,G. Lentine K. W. Kofron R. Pleniewicz E. Wendorf J D. B. Wozniak

• S. F. Stimac -

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\JGS110.cl f

(:

SAltGENT & LUNDY ENGINEERfs rouwocoisei as'EA57 MONMOE STRCCT CHICAOO, ILLINOIS 60603 (38e ) ae0 2000 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 Mr. R. E. Waninski Commonwealth Edison Company Nuclear Engineering Department 1400 Opus Place, Suite 400 Downers Grove, Illinois 60515

Dear Mr. Waninski:

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 i1%. We.are currently reviewing the affect of a change in the positive tolerance to +3%.

Our initial 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 acgommodate a change in the main steam safety valve tolerance to +3% withont 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.

h

q- a SARGENT & LUNDY E N GlN EE MS )'

CHICAGO l

~

Mr. R. E. Waninski. .

June 25, 1990- 1 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, ,

J. G. Saltarelli Senior Mechanical Project Engineer-JGS:cl Copies:

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 J. R. Meister D. V. Radice R; J. Rakowski File Nos. 7.1, 7.5 JGS1/JGS104.wp l

i

)

.i l

1 l

i i

a

[

cm . ~

'(.v- . .

Apri1 25, 1990 AP 2 r :c 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 Per PWR Systems request (Reference), NFS has evauated the proposal to relax the MSSV setpoints to 31 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 -3% drift. Lift setpoints higher 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.

Currently, NFS has not received any staff questions concerning SGTR analyses.

Therefore, NFS rec e ends 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.

l i

l l

If you have any questions or comments, contact John Freeman at ext. 3856, General Office.

l LA >t.h Kenneth N. Kovar Safety Analysis Supervisor l Nuclear Fuel Services KNK:JHF:bl l ID:ZBXL:101:7 l l

cc: K. B. Ramsden R. E. Haninski J. H. Freeman /J. E. Ballard T. Schuster (NLA)

J. Langan L. Bush G. Hagner F. Lentine R. Gestor W. F. Naughton/NFS-CF RSA-CF 1

l 1

l l

. . . - 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 J. S. Tuoto A

Approved: k %_

D. G. B(paM Licence Application Analysis Certified: // JJ4f4(Ld) .

hf*

Robert A. Wiesemann /U rnortssioN" Professional Engineer-0087 .'

Commonwealth of Pennsylvan a ROBERT -m -r , ! - A.Wi ENGINEEH g 't

, no.snt t ,;

Y s ..

h( '

I 9356A: 1

1.0 ' Purpose of' Report This report documents the overpressure; protection provided for the Reactor Coolant System (RCS) in accordance with the ASME Boiler and pressure Vessel Code,Section III, NB-7300.

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 design 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 Withdrawal 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 10CFRSO and includes:-

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

2. The reactor coolant. side of the steam generators.

3. Reactor coolant pumps.

4. A pressurizer 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.

7. The piping,* fittings and valves leading to connecting auxiliary or support systema up to.and including the second isolation valve (from the high' pressure side) on each line.

2.3 The pressurizer provides volume surge capacity and is designed to mitigate pressure increases (as well as decreases) caused by load transients. A pressurizer' spray system condenses.

steam at a rate sufficient to prevent the pressurizer pressure from ' reaching the setpoint of the power-operated relief valves during a step reduction in power level equivalent 1to ten per-cent of full rated load.

9356Atl' -

(1) -

a

The spray nozzle is located in the top heed of the pressur-izer. Spray is initiated when the pressure controlled spray demand signal is above a given setpoint. The spray rate

. . increases proportionally with increasing compensated error-signal until it react.es 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 pressurizer is equipped with 2 power-operated relief valves which limit system pressure for a large' power mismatch i to avoid actuation of.the fixed high pressure reactor trip.

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

Remotely operated stop valves are provided to isolate the y awer-operated relief valves if excessive leakage occurs. The relief valves are designed to limit the pressurizer pressure to a value below the high pressure trip setpoint for all design' transients up to and including the design percentage step load decrease with steam dump but without reactor trip.

Isolated output signals from the pressurizer pressure protec-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.

In the event of unavailability of the pressurizer spray or power operated relief valves, and a complete loss of steam flow to the turbine, protection of the RCS against overpres-sure is afforded by the pressurizer salety valves in conjunc-tion with the steam generator safety valves and a reactor trip initiated by the Reactor Protection System.

There are 3 safety valves with a minimum required capacity of 420,000 lb/ hour for each valve at system design pressure plus 3 allowance for accumulation. The pressurizer 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 system design pres-sure of 2485 psig in accordance with section NB7511. The pressurizer safety valves and power operated relief valves discharge to the pressurizer relief tank (PRT). Rupture disks are installed on the pressurizer relief tank to prevent PRT overpressurization.

Figure 1 shows a schematic arrangement of the pressure reliev-ing devices.

3.0 Sizing of Pressurizer Safety Valves 3.1 The sizing of the pressurizer safety valves is based on analy-sis of a complete loss of steam flow to the turbine with the reactor operating at 102% of Engineered Safeguards Design Power. In this analysis, feedwater flow is also assumed to be 9356A: 1 (2)

lost, and no credit is taken for operation of pressurizer power operated relief valves, pressurizer level control sys-tem, pressurizer spray system, rod control system, steamdump system or steam line power operated 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 pressurizer safety valve capacity is required to be'at least as large as the maximum surge rate into the pressurizer during this transient.

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

of system design pressure for the events 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 discus sed in the FSAR for each transient.

Review of these transients shows that the Turbine Trip results in the maximum system pressure and the caximum 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, pressurizer insurge, and RCS pressure rise.

The automatic steam dump system would normally accommodate the excess steam generation. Reactor coolant temperature and pressure do not significantly increase if the steam dump sys- ,

tem and pressurizer pressure control system are functioning '

properly. If the turbina 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 J 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)

i In this analysis, the behavior of the unit is evaluated for a complete loss of steam load from 102 percent of full power without direct reactor trip; that is, the turbine is assumed to trip without actuating all the sensors for reactor trip on

~"the turbine stop valves. The assumption delays reactor trip until conditions in the RCS result in a trip due to other signals. Thus, the analysis assumes a worst transient. In l addition, no cr, edit is taken for steam dump. Main feedwater i flow is terminated at the time of 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 detailed digital camputer program LOFTRAN. The program simu-lates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer 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 consistent 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 state full power operation including allowances for cali-bration and instrument errors. This results in the maxi-mum 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 9356A: 1 (4)

n i

1

d. Steam release j 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 valves l i setpoint where steam release through safety valves limits I secondar[ysteampressure:: th : ::: ::ir.: c ac . I 4e le ss % lt 0 % ,1t %e. de. siy vs. ' u t , A

e. Pressurizer spray and power operated relief valves No credit is taken for the effect of pressurizer spray and i power operated relief valves in reducing or limiting the l 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 feedwater flow since a stabilized 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 stabilization.

9 Raoc. b h p S. 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 pressurizer. pressure, Overtemperature AT, high pressurizer water level, and low-low steam generator water level.

The results of the Turbine Trip transient are shown in Figures 2 and 3. Figure 2 shows the pressurizer pressure, the reactor coolant pump discharge pressure, which is the point-of highest pressure in the RCS, and the pressuris.er 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 pressurizer 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 pressurizer 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 ;000, 1971 Edition Winter 1972 Addenda.

9356A:1 *

(5)

2. Topical Report - Overpressure Protection'for Westinghouse

?res surizer Water Reactors, WCAP 7 769, Rev. 1, J un e 19 72.

, _ 3. Certified Safety Val've Capacity, Calculation No. CPA 3 44; FA-792, July 23, 1980, Corrected January 22, 1981.

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

5. CAI 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 ONB & Broken Pump Sha f t, Calculation No. CN-PP-80-129, November, 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-Il5, November, 1980.

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

^

10. CAE OFA FSAR Amendment - Rod Withdrawal at 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.

4 I

9356A:1 (6)