ML17331B133

DC Cook Units 1 & 2 Main Steam Safety Valve Lift Setpoint Tolerance Relaxation.

ML17331B133
Person / Time
Site:	Cook
Issue date:	12/31/1993
From:	WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:
Shared Package
ML17331B132	List: ML17331B131 ML17331B133
References
SECL-91-429, SECL-91-429-R02, SECL-91-429-R2, NUDOCS 9312230047
Download: ML17331B133 (157)

Text

DONALD C. COOK UNITS 1 R 2 MIJN STEAM SAHHY VALVE LIFI'ETPOINT TOLERANCE RELAXATION Nuclear and Advanced Technology Division Westinghouse Electric Corporation December 1993 e1993 Westinghouse Electric Corporation All Rights Reserved 9312230047 931217 PDR ADOCK 05000315

. P PDR

SECL-91<29, Revision 2 TABLE OF CONTENTS

~SE I~N PA E List of Tables List of Figures nI Safety Evaluation Check List VI Introduction Licensing Basis Evaluations Non-LOCA 5 LOCA 17 Containment Integrity 24 Steam Generator Tube Rupture 24 Component Performance 25 Systems Evaluation 26 Radiological Evaluation 26 Plant Risk Analysis /PE) 26 Plant Risk Analysis (non-IPE) 26 I&C Systems 27 Technical Specifications 27 Assessment of No Unreviewed Safety Question 28 Conclusion 31 References 32 Appendix A: Significant Hazards Evaluation Appendix B: Recommended Technical Specification Marked-Ups 91429R2.wpf

LIST OF TABLES TABLE PA E Table 1: Main Steam Safety Valve LiftSetpoints Table 2: DNB Design Basis Transients Not Affected by MSSV LiftSetpoint Tolerance Increase Table 3: Unit 1 Turbine Trip Sequence of Events 33 Table 4: Unit 2 Turbine Trip Sequence of Events 35 Table 5: Current Licensing Basis Steam Line Safety Valves per Loop 37 Table 6: MSSV Setpoint Increase Steam Line Safety Valves per Loop 38 Table 7: Unit 1 Low Pressure Low Temperature Input Parameters 39 Table 7a: Unit 1 Initial Input Parameters for the Small Break LOCA Analysis Table 8: Unit 1 Low Pressure High Temperature Input Parameters 41 Table 9: Unit 2 Low Pressure High Temperature Input Parameters 42 Table 10: Unit 1 Small Break LOCA Evaluation Time Sequence of Events 43 Table 10a: Unit 1 Small Break LOCA Analysis Time Sequence of Events Table 11: Unit 1 Small Break LOCA Evaluation Summary of Results 45 Table 11a: Unit 1 Small Break LOCA Analysis Summary of Results Table 12: Unit.2 Small Break LOCA Evaluation 46 Time Sequence of Events 47 Table 13: Unit 2 Small Break LOCA Evaluation Summary of Results 48 ubxxx.wpf: Id-121393

SECI 91<29, Revision 2 LIST OF FIGURES

~IGURB Figure la: Illustration of Overtemperature and Overpower hT Protection for Unit 1 Figure 1b-c: Illustration of Overtemperature and Overpower hT Protection for Unit 2 (mixed and full V-SH cores)

Figure 2: Unit 1 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback: Pressurizer Pressure and Water Volume Figure 3: Unit 1 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback: Nuclear Power and DNBR Figure 4: Unit 1 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback: Core Average Temperature and Loop Temperature Figure 5: Unit 1 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback; Steam Generator Pressure and MSSV Relief Rate Figure 6: Unit 1 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback: Pressurizer Relief Rate Figure 7: Unit 1 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Pressurizer Pressure and Water Volume Figure 8: Unit 1 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Nuclear Power and DNBR Figure 9: 'nit 1 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Core Average Temperature and Loop Temperature Figure 10: Unit 1 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Steam Generator Pressure and MSSV Relief Rate Figure 11: Unit 1 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Pressurizer Relief Rate Figure 12: Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Pressurizer Pressure and Water Volume Figure 13: Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Nuclear Power and DNBR Figure 14: Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Core Average Temperature and Loop Temperature f '1429R2.wp

SECL-91<29, Revision 2 LIST OF FIGURES (Continued)

~FI @RE Figure 15: Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Steam Generator Pressure and MSSV Relief Rate Figure 16: Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Pressurizer Relief Rate Figure 17: Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Pressurizer Pressure and Water Volume Figure 18: Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Nuclear Power and DNBR Figure 19: Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Core Average Temperature and Loop Temperature Figure 20: Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Steam Generator Pressure and MSSV Relief Rate Figure 21: Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Pressurizer Relief Rate Figure 22a-b: Unit 2 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback: Pressurizer Pressure and Water Volume Figure 23a-b: Unit 2 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback: Nuclear Power and DNBR Figure 24a-b: Unit 2 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback: Core Average Temperature and Loop Temperature Figure 25a-b: Unit 2 Turbine Trip Event Without OPressure Control, Minimum Reactivity Feedback: Steam Generator Pressure and MSSV Relief Rate Figure 26a-b: Unit 2 Turbine Trip Event Without Pressure Control, Minimum Reactivity Feedback: Pressurizer Relief Rate Figure 27a-b: Unit 2 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Pressurizer Pressure and Water Volume Figure 28a-b: Unit 2 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Nuclear Power and DNBR 91429Rz.wpf 1v

SECI 91-429, Revision 2 LIST OF FIGURES (Continued)

FI URE Figure 29a-b: Unit 2 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Core Average Temperature and Loop Temperature Figure 30a-b: Unit 2 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Steam Generator Pressure and MSSV Relief Rate Figure 31a-b: Unit 2 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback: Pressurizer Relief Rate Figure 32a-b: Unit 2 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Pressurizer Pressure and Water Volume Figure 33a-b: Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Nuclear Power and DNBR Figure 34a-b: Unit 2 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Core Average Temperature and Loop Temperature Figure 35a-b: Unit 2 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Steam Generator Pressure and MSSV Relief Rate Figure 36a-b: Unit 2 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Pressurizer Relief Rate Figure 37a-b: Unit 2 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Pressurizer Pressure and Water Volume Figure 38a-b: Unit 2 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Nuclear Power and DNBR Figure 39a-b: Unit 2 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Core Average Temperature and Loop Temperature Figure 40a-b: Unit 2 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Steam Generator Pressure and MSSV Relief Rate Figure 41a-b: Unit 2 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Pressurizer Relief Rate 9 1 429R2.wp f v

SECI 91-429, Revision 2 Customer Reference No(s).

PO: 04877-040-IN Westinghouse Reference No(s).

WESTINGHOUSE NUCLEAR SAFETY SAFETY EVALUATIONCHECK LIST

1) NUCLEAR PLANT(S): DONALD'C COOK NITS 1 AND 2

2) SUBJECT (TITLE): RELAXATI N F MSSV SETPOINT TOLERANCE TO +/-  %

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 UFSAR?

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

(3.3) Yes No X A test or experiment not described in the UFSAR?

(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 UFSAR be increased?

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

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

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

(4.5) Yes No X Will the consequences of a malfunction of equipment important to safety previously evaluated in the UFSAR 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 UFSAR be created?

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

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SECL-91-429, Revision 2 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 attached safety evaluation summarizes the justification for answers given in Part A 3.4 and Part B of this safety evaluation check list:

'Reference to documents containing written safety evaluation:

F R UF AR PDATE Pages: Tables: Figures:

Reason for/Description of Change:

UFSAR Mark-u s e rovided b se arate transmittal

6) SAFETY EVALUATIONAPPROVAL LADDER:

1 6.1) Prepared by (Nuclear Safety):

6.2) Reviewed by (Nuclear Safety):

dccook.wp f-121093 vn

SECI 91<29, Revision 2 DONALD C. COOK UNITS 1 &2 INCREASED IVORYÃ ST1MH SAFRXY VALVESEIPOINT TOLERANCE SAFEIY EVALUATION I. INTRODUCTI N American Electric Power Service Corporation (AEPSC) has found that over an operating cycle the setpoint of the Main Steam Safety Valves (MSSVs) can change by more than 1% from the original set-pressure. AEPSC has requested that Westinghouse perform an evaluation to increase the lift setpoint tolerance on the MSSVs at Donald C. Cook Units 1 & 2. The following safety evaluation is provided to support changing the as-found liftsetpoint tolerance as stated by the Technical Specifications from J1% to +3%.

During normal surveillance, if the valves are found to be within +3%, they will be within the bases of the accident analyses, however, the valves will be reset to J1% to account for future accumulation of drift. Thus, this evaluation permits a J3% setpoint tolerance to address as-found conditions.

The MSSVs are located outside containment upstream of the Main Steam Isolation Valves. The purpose of the valves is to prevent overpressurization of the steam generators. In order to accomplish this, a bank of five valves is located on each of the four steam generators, and the relief capacity is designed such that the total steam flow from the 20 valves will bound that produced by the limiting licensing-basis analysis. For Donald C. Cook, the total relief capacity of the 20 valves is

17. 153 E6 ibm/hr at 1186.5 psia (1171.5 psig).

The lift setpoints of the individual valves on each steamline are staggered at different pressures to minimize chattering once the valves are actuated. Staggering the valves also minimizes the total number of valves actuated during those transients where less than the maximum relief capacity is required thereby reducing maintenance requirements on the valves. The actual setpoints are provided in Table 1 and are documented in Tables 4.7-1 and 3.7-4 of the Units 1 and 2 Technical Specifications, respectively (Reference 1).

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SECL-91<29, Revision 2 The operation of the Class 2 main steam safety valves (MSSVs) is governed by the ASME Code (Reference 2). AEPSC will maintain the design basis of the MSSVs by ensuring that the valves, if outside the J1% tolerance, will be recalibrated to within J1%. The purpose of this evaluation is to provide a quantification of the effects of a higher as-found liftsetpoint tolerance. This safety evaluation will address the effects of the J3% as-found tolerance on UFSAR accident analyses (non-LOCA, LOCA, SGTR) and will document how the effects are accounted for within the accident analyses and the acceptability of the increase in the liftsetpoint tolerance.

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SECI 91-429, Revision 2 TABLE 1 MAINSTEAM SATINY VALVELIFI'ETPOINT Value Number .Lift Se oint 1 SV-1 1065 psig (1080 psia)

SV-1 1065 psig (1080 psia)

SV-2 1075 psig (1090 psia)

SV-2 1075 psig (1090 psia)

SV-3 1085 psig (1100 psia)

References:

Table 4.7-1 of the Unit 1 Technical Specifications and Table 3.7-4 of the Unit 2 Technical Specifications 91429R2.wpf

SECL-91<29, Revision 2 II. LICENSING BASIS Title 10 of the Code of Federal Regulations, Section 50.59 (10CFR50.59) 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 Updated Final Safety Analysis Report (UFSAR). 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 liftsetpoint tolerances involves a change to the Donald C. Cook 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).

The non-LOCA safety analyses will be examined to determine the impact of the MSSV liftsetpoint tolerance relaxation on the DNB design basis as well as the applicable primary and secondary system pressure limits. The long-term core cooling capability of the secondary side will also be considered.

The LOCA evaluation will investigate the effects on the licensing basis small break analysis in terms of peak clad temperature, and any adverse effects on the steam generator tube rupture event and subsequent dose release calculations will also be determined.

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SECI 91<29, Revision 2 III. EVALUATIONS The results of the various evaluations from the Nuclear Safety related disciplines within Westinghouse scope are discussed in the following sections.

1. Non-LOCA Evaluation The non-LOCA accident analyses that are currently presented in the UFSAR modelled the MSSVs as a'ank of five valves, all of which having a lift setpoint equal to that of the highest set valve (1100 psia) plus 3% to account for accumulation. All of the analyses and evaluations performed for this report modelled the staggered behavior of the MSSVs. Specifically, each valve was assumed to operate individually. Moreover, the analyses/evaluations of this report modelled the flow rate of each valve to ramp linearly from no flow at its lift setpoint (nominal Technical Specification setpoint plus or minus the 3% tolerance value) to full open flow at its full open point (3% above the pressure at which the valves were assumed to pop open - i.e., accumulation effect).

For the purposes of this evaluation, all 20 MSSVs are assumed to lift3% above the Technical Specification lift setpoint and achieve full rated flow (normally at 3% abov:: the setpoint) 6% above the setpoint.

hT Protection The increase in the MSSV liftsetpoint tolerance has the potential to impact the Overtemperature hT and Overpower hT setpoint equations. Referring to Figure la for Unit 1 and Figures 1b and 1c (which are the most limiting case for each unit/core type), 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.

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SECI 91<29, Revision 2, In order to evaluate the effects of the increase in the setpoint tolerance, the Overtemperature hT and Overpower dT 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. Thus, changes to the Overtemperature and Overpower Technical Specifications are not needed. The results of this evaluation are presented as Figures la, lb, and 1c.

~DNB Even The transients identified in Table 2 are analyzed in the D. C. Cook 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 (i.e., only the core is modelled), 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 the ANALYSIS section of this safety evaluation. Thus, based on the above, these yon-LOCA DNB transients are not adversely impacted by the proposed change, and the results and conclusions presented in the UFSAR remain valid, Boron Dilution Event The boron dilution event (14.1.5) is analyzed to demonstrate that the operators (or the automatic mitigation circuitry) have sufficient time to respond prior to reactor criticality. The secondary system is not modeled in the analysis of this event, and thus, changes to the MSSVs have no impact on this event. Therefore, the results and conclusions presented in the UFSAR remain valid.

Steamline Break Mass &: Ene Releases For the steamline break mass and energy releases, the'steam release calculations are insensitive to the changes in the MSSV liftsetpoints since the vast majority of these calculations result in depressurizations of the secondary side such that the MSSVs are not actuated. For the 91429Rz.wpf

SECI 91-429, Revision 2 TABLE 2 DNB DESIGN BASIS TRANSIENTS NOT AFFECTED BY MSSV LIFI'ETPOINT TOLERANCE INCREASE"'vent UFSAR Section Excessive Heat Removal Due to 14.1.10 Feedwater System Malfunction Excessive Load Increase Incident 14.1.11 Rupture of a Steam Pipe (Steamline 14.2.5 Break - Core Response)

Loss of Reactor Coolant Flow 14.1.6 includes Locked Rotor Analysis)

Uncontrolled RCCA Bank Withdrawal 14.1.1 From a Subcritical Condition Uncontrolled RCCA Bank Withdrawal 14.1.2 at Power RCCA Misalignment 14.1.3 91429R2.wpf

SECI 91-429, Revision 2 smaller break cases that might result in a heatup, one MSSV per steam generator is sufficient (based on the existing analyses) to provide any required heat removal following reactor trip. The secondary pressures will be no greater than those presently calculated. Thus the existing steamline break mass and energy release calculations remain valid.

Event UFSAR Sectio Steamline Rupture Mass & Energy Releases WCAP-11902 Inside Containment Supplement 1

'teamline Rupture Mass & Energy Releases WCAP-10961 Rev 1 Outside Containment for (current)

Equipment Environmental Qualification Submittal AEP:NRC:1140*

(approved 11/20/9 1)

Submittal AEP:NRC:1140 "Technical Specification Change Request, BIT Boron Concentration Reduction," March 26, 1991.

(included in WCAP-11902, Supplement 1)

Lon -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/LOOP), and the core remains covered and in a eoolable geometry (FLB). These transients are listed below.

Event Loss of All AC Power to the Plant 14.1.12 Auxiliaries (Loss of Offsite Power - LOOP)

Loss of Normal Feedwater (LONF) 14.1.9 Feedwater System Pipe Break (FLB)* 14.1.8 C

• The Feedwater System Pipe Break event is not part of the Unit 1 licensing basis and is presented in the Unit 1 UFSAR for information purposes only.

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 4

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SECL-91<29, Revision 2 generator back pressure increases, the amount of AFW delivered will be reduced. For the loss of normal feedwater and the loss of all AC power to the Plant Auxiliaries events, evaluations were performed in which the staggered actuation of the MSSVs was taken into account.

The safety analysis presented in the current UFSAR assumed an AFW flow rate of 450 gpm, split evenly to all four steam generators. The evaluations done for this report concerning loss of normal feedwater (LONF) for Units 1 and 2, as well as loss of all AC power to the plant auxiliaries (LOOP) for Unit 1, demonstrated that the secondary side pressures will not exceed 1123 psia during the time AFW is delivered to the steam generators. Based on Reference 10, the AFW assumptions modeled in the safety analysis remain valid for steam generator backpressures up to 1123 psia. Since the evaluation, in which a +3% MSSV setpoint tolerance was assumed, showed that the secondary side pressure transient will not preclude the AFW flow rates assumed in the analysis from being supplied to the steam generators, the existing analyses remain valid for Unit 1 LONF/LOOP and Unit 2 LONF.

The Loss of Offsite Power event (LOOP) for Unit 2 was also evaluated for this-report. The LOOP safety analysis presented in the current UFSAR for Unit 2 assumed an AFW flow rate of 430 gpm split evenly to all four steam generators. The recent'evaluation done for this report took credit for the staggered actuation of the MSSVs as well as a +3% setpoint tolerance, as discussed earlier. The evaluation yielded results similar to those discussed above for Unit 1. The secondary side pressure for this Unit 2 evaluation was demonstrated not to exceed 1133 psia during the period AFW is supplied. Based on Reference 10, the secondary side pressure transient was found not to preclude the AFW flow rates assumed in the analysis from being delivered to the steam generators. Therefore, the existing Loss of Offsite Power analysis for Unit 2 remain valid.

The evaluations for the LONF/LOOP events for both Unit 1 and Unit 2, as discussed above, demonstrate that the respective analyses are still applicable even if a MSSV liftsetpoint tolerance of

+3% is assumed. Therefore the results and conclusions presented in the Donald C. Cook Unit 1 &2 UFSAR remain valid.

The evaluation done for this report for the Unit 2 Feedline Break event demonstrated that, the secondary side pressure will not exceed 1133 psia during the period when AFW is being delivered.

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SECL-91<29, Revision 2 At 1133 psia, an AFW flow rate of 685 gpm with asymmetric flow splits to the three intact steam generators could be supplied based on information contained in Reference,10. The current analysis for this event assumed a total AFW flow rate of 600 gpm with an even split of 200 gpm to the three intact steam generators. Since the total AFW flow rate is more than sufficient to accommodate AFW flow split deviations of as much as 25 gpm per loop, the current Feedline Break analysis continue to be applicable and remain bounding for this evaluation. Therefore, the results and conclusions presented in the Unit 2 UFSAR (14.2.8) remain valid.

-3% Tolerance:

The secondary steam releases generated for the locked rotor offsite dose calculations for Unit 2 could be potentially affected by an increase in the MSSV setpoint tolerance from -1% to -3%. Reference 9 transmitted the most recent locked rotor dose analysis. Given that the radiological assumptions used in the Reference 9 analysis do not change with an increase in MSSV setpoint tolerance (i.e.,

rods-in-DNB and primary to secondary leakage remain at 11% and 1 gpm respectively) the only effect the tolerance increase would have would be on the mass release values. 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 (547'F) by bleeding steam. Over the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (2-8 hours), the operators will cool the plant down such that Mode 4 operation (hot shutdown) can be entered.

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 (581.3'F and 547'F, respectively). Thus, as long as the increased liftsetpoint 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 (Reference 9),

The existing mass release calculations were performed using the temperatures previously identified (581.3'F and 547'F). Per the Donald C. Cook Technical Specifications, the lowest set MSSV on each steam generator will open at 1080 psia (1065 psig) not including any tolerance. Based on the ASME Steam Tables (Reference 6) at saturated conditions, 547'F corresponds to 1020.1 psia and 9 l-429R2.wp f 10

SECL-91-429, Revision 2 represents the lowest steam pressure considered in the mass calculations. Thus, the existing releases include a reseat pressure approximately 5.5% 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.

The operating windows that are applicable for Unit 1 operation are bounded by the Unit 2 dose analysis. Therefore, the mass releases for Unit 2, as found in Reference 9, are applicable to Unit 1.

Evaluation Summa Thus, based on the discussions presented above, only one UFSAR non-LOCA transient is impacted

'uch that a new analysis must be performed in order to address the effects of the MSSV lift setpoint tolerance increase from J1% to J3%. This event is the loss of external load/turbine trip accident.

For the other transients, the results and conclusions presented in the Donald C. Cook Unit 1 &2 UFSAR remain valid.

Loss of External Load/Turbine Tri The loss of external load/turbine trip event is presented in Section 14.1.8 of the Donald C. Cook 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 hT, 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 91429R2.wpf

SECL-91<29, Revision 2 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 6). This modified version of LOFTRAN only differs from the standard code version in the way the MSSVs are modelled. 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. Whereas the standard LOFTRAN version program conservatively models the MSSVs as a bank of five valves, all having one common liftsetpoint. By modelling the staggered behavior of the MSSVs, a more accurate simulation of how the valves actually behave is achieved. Since higher steam pressures are conservative for this event, no blowdown or hysteresis behavior was assumed.

Consistent with the existing UFSAR analysis, all assumptions were the same as previously used unless specifically noted. The following assumptions were used in this analysis:

a. Initial power, temperature, and pressure were at their nominal values consistent with:

1) ITDP methodology (WCAP-8567) for Unit 1, with the exception that a 2%

conservatism on initial core power was assumed.

2) RTDP methodology (WCAP-11397) for Unit 2, with no exceptions.

b. Turbine trip was analyzed with both minimum and maximum reactivity feedback.

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

91429R2.wpf . 12

SECI 91<29, Revision 2

d. The steam generator PORV and steam dump valves were not assumed operable. This assumption maximizes secondary pressure which in turn maximizes the primary temperature for DNBR and primary pressure for pressure cases.

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

f. Only the overtemperature dT, high pressurizer pressure, and low-low steam generator water level reactor trips were assumed operable for the purposes of this analysis.

g. The flow rate for each MSSV was modelled to ramp linearly from no flow at its lift setpoint (3% above the nominal Technical Specification setpoint) to full open flow at its full open point (6% above the nominal setpoint), The full open flow rate is based on a reference full flow capacity of 238 ibm/sec at 1186.5 psia (based on the ASME rated flow for these valves). For secondary side pressures between the initial full open point for each valve and 1186.5 psia, the full open flow rate was modelled to vary proportionally with pressure. This assumption maximizes secondary pressure which in turn maximizes the primary temperature for DNBR and primary pressure for pressure cases.

R~esul Four cases for each unit/core type (i.e. Unit 1, Unit 2 mixed core,and Unit 2 full V5 core) 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 most limiting cases in the current UFSAR continue to be the most limiting cases. The calculated sequence of events for the four cases for each unit are presented in Tables 3 and 4.

9l429R2.wp f 13

SECI 91<29, Revision 2 Case A:

Figures 2 through 6 show the transient response for the turbine trip event under minimum reactivity feedback 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 7 through 11 show the transient response for the turbine trip event under rnaxirnum reactivity feedback conditions without pressure control. The core power is observed to undergo a momentary increase. This is due to positive reactivity being inserted as a result of the increase in coolant density caused by the increase in primary pressure. This affect is quickly countered by the subsequent temperature rise brought on by the abrupt loss of the heat sink. 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 12 through 16 show the transient response for the turbine trip event under maximum reactivity feedback conditions with pressure control ~ The core power is observed to undergo a momentary increase. This is due to positive reactivity being inserted as a result of the increase in coolant density caused by the rapid increase in primary pressure. This affect is quickly countered by the subsequent temperature

\

rise brought on by the abrupt loss of the heat sink. The reactor is tripped on low-low steam generator water level. The DNBR increases throughout the transient and never drops below the initial value, The pressurizer relief valves.and sprays maintain primary pressure 91429R2.wpf 14

SECI 91-429, Revision 2 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 D:

Figures 17 through 21 show the transient response for the turbine trip event under minimum reactivity feedback conditions with pressure control. The reactor is tripped on high pressurizer pressure.

Although the DNBR value decreases below the initial value, it remains well above the limit throughout the entire transient. The pressurizer relief valves and sprays maintain primary pressure below 110% of the design value. The main steam safety valves are also actuated and maintain secondary pressure below 110% of the design value.

Anal i Concl ion nit 1 Based on the results of these Unit 1 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.

UNIT 2: a mixed and b full V-5 cores Case A:

Figures 22a through 26b ("a" designates mixed core figures and "b" denotes full V-5 core figures) show the transient response for the turbine trip event under minimum reactivity feedback conditions without pressure control for both core types. 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.

91429R2.wpf 15

SECL-91<29, Revision 2 Case B:

Figures 27a through 31b show the transient response for the turbine trip event under maximum reactivity feedback conditions without pressure control for both mixed and full V-5 core types. The core power is observed to undergo a momentary increase, This is due to positive reactivity being inserted as a result of the increase in coolant density caused by the rapid increase in primary pressure.

This affect is quickly countered by the subsequent temperature rise brought on by the abrupt loss of the heat sink. 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 32a through 36b show the transient response for the turbine trip event under maximum reactivity feedback conditions with pressure control for the two applicable Unit 2 core types. The core power is observed to undergo a momentary increase. This is due to positive reactivity being inserted as a result of the increase in coolant density caused by the rapid increase in primary pressure.

This affect is quickly countered by the subsequent temperature rise brought on by the abrupt loss of the heat sink. The reactor is tripped on low-low steam generator water level ~ The DNBR increases throughout the transient and never drops below the initial value.. 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.

Case D:

Figures 37a through 41b show the transient response for the turbine trip event under minimum reactivity feedback conditions with pressure control for both the mixed and full V-5 cores. The reactor is tripPed on high pressurizer pressure. Although the DNBR value decreases below the initial value, it remains well above the limit throughout the entire transient. The pressurizer relief valves and sprays maintain primary pressure below 110% of the design value. The 91429R2.wpf 16

SECL-91<29, Revision 2 main steam safety valves are also actuated and maintain secondary pressure below 110% of the design value.

Anal is Conclusion nit 2 Based on the results of these Unit 2 mixed and full core 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.

N n- A Conclusio The effects of increasing the as-found lift setpoint tolerance on the main steam safety valves 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 safety evaluation, all applicable acceptance criteria for this event have been satisfied and the conclusions presented in the UFSAR are s'till valid. Thus, with respect to the non-LOCA transients, 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,

2. CA and A Related Evaluations La e Break CA The current large break LOCA analyses for Donald C. Cook Units 1 and 2 were performed with the NRC approved 1981 Evaluation Model plus BASH. After a postulated large break LOCA occurs, the heat transfer between the reactor coolant system (RCS) and the secondary system may be in either direction, depending on the relative temperatures. In the case of continued heat addition to the secondary system, the secondary system pressure increases and the MSSVs may actuate to limit the pressure. However, this does not occur in the large break evaluation model since no credit is taken for auxiliary feedwater actuation. Consequently, the secondary system acts as a heat source. in the 91429R2.wpf 17

SECL-91<29, Revision 2 l

postulated large break LOCA transient and the secondary pressure does not increase. Since the secondary system pressure does not increase, it is not necessary to model the MSSV setpoint in the large break evaluation model. Therefore, an increase in the allowable MSSV setpoint tolerance for Donald C. Cook Units 1 and 2 will not impact the current UFSAR large break LOCA analyses.

mall Break CA The small break LOCA analyses for Donald C. Cook Units 1 and 2 were performed with the NRC approved Evaluation Model using the NOTRUMP code. After a postulated small break LOCA occurs, the heat transfer between the RCS and the secondary system may be in either direction depending on the relative temperatures. In the case of continued heat addition to the secondary system, the secondary system pressure increases which leads to steam relief via the MSSVs. In the small break LOCA, the secondary flow aids in the reduction of RCS pressure. Subsequently, Donald C. Cook Units 1 and 2 were reanalyzed to determine the impact of an increased MSSV setpoint tolerance of 3%.

The licensing basis small break LOCA analysis for Donald C. Cook Unit 1 included a safety evaluation to address a 25 gpm charging pump flow imbalance and operation with the high head safety injection cross tie valve closed at 3250 MWt core power level. Also, a safety evaluation had been performed which modeled an increased auxiliary feedwater enthalpy delay time. These assumptions were incorporated in the increased MSSV setpoint tolerance NOTRUMP analysis of the limiting 3 inch break for Unit 1. However, in order to obtain a direct sensitivity for the increased MSSV setpoint tolerance, a NOTRUMP analysis was also performed incorporating these assumptions but modelling the original MSSV setpoints.

In addition, a 3 inch NOTRUMP analysis was performed for the low pressure, high temperature operating condition for Unit 1 since a safety evaluation had been originally performed as part of the licensing basis analysis. The increased MSSV setpoint tolerance, a core power level of 3250 MWt

.with the. high head cross tie valve closed, and a 25 gpm charging pump flow imbalance were assumed for the analysis of the low pressure, high temperature case.

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SECL-91-429, Revision 2 Donald C. Cook Unit 2 was reanalyzed for the limiting 3 inch break, low pressure and high temperature operating condition with the high head cross tie valve closed. The power shape axial offset was reduced from the licensing basis analysis of +30% to +13% for the MSSV increase analysis. An axial offset of +13% is equal to the value assumed in the licensing basis large break LOCA analysis. In addition, the licensing basis analysis conservatively assumed a maximum" assembly average power (P+ of 1.519. The 3% increased MSSV setpoint tolerance analysis assumed a P~ which was reduced to 1.46. In order to obtain a direct sensitivity for the increased MSSV setpoint tolerance, a NOTRUMP analysis was performed incorporating these assumptions but modelling the original MSSV setpoints.

Tables 5 and 6 summarize the MSSV setpoints used in the Donald C. Cook Units 1 and 2 current licensing basis small break LOCA analyses and the increased MSSV setpoint tolerance analyses, respectively. Tables 7 and 8 summarize the initial input assumptions used in the Unit 1 analysis.

The Unit 2 initial input assumptions are summarized in Table 9, The time sequence of events and results of the Unit 1 analysis are summarized in Tables 10 and 11, respectively. The limiting peak clad temperature calculated is 1879'F, including a 25'F burst and blockage penalty, for the 3% increased MSSV setpoint tolerance case at 3250 MWt and the low pressure, low temperature operating conditions'. This value is less than the acceptance criteria limit of 2200'F. The maximum local metal-water reaction is 3A7%, which is well below the embrittlement limit of 17% as required by 10CFR50.46. The total core metal-water reaction is less than 1.0%, corresponding to less than 1.0 percent hydrogen generation, as compared to the 1%

criterion of 10CFR50.46.

The time sequence of events and results of the Unit 2 analysis are summarized in Tables 12 and 13, respectively. 'Ihe limiting peak clad temperature calculated is 2125'F, including a 12'F artificial leak-by penalty and 157'F burst and blockage penalty, for the 3% increased MSSV setpoint tolerance case at 3250 MWt and low pressure, high temperature operating condition. This value is less than the acceptance criteria limit of 2200'F. The maximum local metal-water reaction is 4.26%, which is These results are from calculations using a nominal auxiliary fcedwater flow. A subsequent analysis using a morc conservative minimum auxiliary feedwater flow rate is presented in thc next section.

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SECI 91<29, Revision 2 well below the embrittlement limit of 17% as required by 10CFR50.46. The total core metal-water reaction is less than 1.0%, corresponding to less than 1.0 percent hydrogen generation, as compared to the 1% criterion of 10CFR50.46.

Additional Small Break CA Anal ses The small break LOCA analysis for Cook Unit 1, previously discussed, used nominal Auxiliary Feedwater (AFW) flow rates (1258 gpm total delivery), whereas minimum AFW flow rates were used for Cook Unit 2, Since minimum AFW flow rates are more limiting, the small break LOCA for Cook Unit 1 for +3% MMSV setpoint tolerance was reanalyzed using lower auxiliary feedwater flow rates (750 gpm total delivery). The following presents the results of the revised small break LOCA analyses performed for Donald C. Cook Unit 1.

Based on the Cook Unit 1 analyses presented in the previous section, two additional small break LOCA cases were run to address a relaxation to +3% for the MSSV setpoint tolerance. First, the original LPLT (Low Pressure, Low Temperature) case presented above, the results of which are shown in Tables 10 and 11, was rerun modeling 750 gpm total AFW system flow rate. As was demonstrated in References 11 and 12, the LPLT case is the limiting case for the pressure/temperature operating window for Cook Unit 1, and that will not change due to the reduction in AFW flow. In addition, since only the limiting break size (3 inch) was previously analyzed, a 2 inch break was also analyzed for the 750 gpm AFW flow rate to provide further assurance that the limiting break size has not shifted to a smaller break size due to the reduction in the AFW flow rate.

Note that since both the reduction in AFW delivered flow and the increase in the setpoint tolerance to

>3% tend to shift the limiting break size to a smaller break, it is not necessary to consider that the limiting break could be larger than was presented in the current licensing basis analysis which demonstrated that the 3 inch break is limiting.

The MSSV performance assumed in these new cases is shown in Table 6. The initial input parameters assumed for these new cases are shown in Table 7a, and are compared with the original licensing basis in Reference 11. If the new analysis values from Table 7a are compared with the original evaluation cases shown in Table 7, very few differences are evident. Except for the auxiliary feedwater flow rate an'd a slight increase in the accumulator water temperature, the initial RCS 91429R2.wpf 20

SECL-91<29, Revision 2 pressure was lowered to cover a safety evaluation that was performed for pressurizer pressure uncertainty. Incorporating this new RCS pressure had a negligible effect on the vessel inlet and outlet temperatures and the steam pressure assumed for reactor steady-state operation (prior to initiation of the transient). One final additional change is in the AFW enthalpy delay. The lower AFW flow rate would result in a longer delay. The current NOTRUMP model has been improved to model the volume of hot main feedwater that must be purged from the piping prior to cold AFW being delivered to the steam generator, and the delay is calculated by the model. Other than these minor differences, and the intended change (i.e., reduce AFW flow rate and increase accumulator water temperature),

the initial conditions assumed for the additional runs are identical to the runs performed for the previous section.

The time sequence of events and results of the Unit 1 analyses are summarized in Tables 10a and 11a, respectively. The limiting Peak Clad Temperature (P~ calculated is 2068'F, including a 117'F burst and blockage penalty, for the +3% increased MSSV setpoint tolerance case at 3250 MWt and low pressure, low temperature operating condition. This value is less than the acceptance criteria limit of 2200'F, and is almost the same computed result that is seen for D.'. Cook Unit 2 (the pre-burst/blockage PCT of 1951'F versus 1956'F). The maximum local metal-water reaction is 5.06%,

which is well below the embrittlement limit of 17% as required by 10 CFR 50.46. The total core metal-water reaction is less than 1.0%, corresponding to less than 1.0 percent hydrogen generation, as compared to the 1% criterion of 10 CFR 50.46.

The >3% increased MSSV setpoint tolerance has been analyzed for the Donald C. Cook Nuclear Plant Unit 1 for the small break LOCA analyses performed by Westinghouse. The potential effect of this change on the FSAR analysis results for the small break LOCA analysis was examined via reanalysis and although the results are more limiting than previous analysis cases, it was shown that the effect of the increased MSSV setpoint tolerance did not result in exceeding any of the following design or regulatory limits:

1. The calculated peak fuel element cladding temperature is below the requirements of 2200'F.

2. The amount of fuel element cladding that reacts chemically with water or steam does not exceed 1 percent of the total amount of Zircaloy in the reactor.

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SECI 91-429, Revision 2

3. The cladding temperature transient is terminated at a time when the core geometry is still amenable to cooling. The localized cladding oxidation limit of 17 percent is not exceeded during or after quenching.

4. The core remains amenable to cooling during and after the break.

5. The core temperature is reduced and decay heat is removed for an extended period of time, as required by the long-lived radioactivity remaining in the core.

Therefore, it is concluded that a relaxation to J3% for the MSSV setpoint tolerance is acceptable from the standpoint of the small break LOCA FSAR accident analyses discussed in this safety evaluation.

Post-LOCA Lon Term Core Coolin The Westinghouse licensing position for satisfying the requirements of 10CFR50.46 Paragraph (b),

Item (5), "Long Term Cooling," concludes that the reactor will remain shut down by borated ECCS water residing in the RCS/sump after a LOCA. Since credit for the control rods. is not taken for a large break LOCA, the borated ECCS water provided by the accumulators and the RWST must have a boron concentration that', when mixed with other water sources, will result in the reactor core remaining subcritical assuming all control rods out. The calculation is based upon the reactor steady state conditions at the initiation of a LOCA and considers sources of both borated and unborated fluid in the post-LOCA containment sump. The steady state conditions are obtained from the large break LOCA analysis which, as stated above, does not take credit for MSSV actuation. Thus the post-LOCA long-term core cooling evaluation is independent of the MSSV setpoint tolerance, and there will be no change in the calculated RCS/sump boron concentration after a postulated LOCA for Donald C. Cook Units 1 and 2.

Hot Switchover to Prevent Potential Boron Preci itation Post-LOCA hot leg recirculation time is determined for inclusion in emergency operating procedures to ensure no boron precipitation in the reactor vessel following boiling in the core. This time is 91429R2.wpf 22

SECL-91<29, Revision 2 dependent on power level and the RCS, RWST, and accumulator water volumes and with their associated boron concentrations. The proposed MSSV setpoint tolerance increase to 3% does not affect the power level or the boron concentrations assumed for the RCS, RWST, and accumulator in the hot leg switchover calculation for Unit 1. The proposed MSSV setpoint tolerance increase to 3%'oes not affect the boron concentrations assumed for the RCS, RWST, and accumulator in the hot leg switchover calculation for Unit 2. The current licensing basis hot leg.switchover calculation for Unit 2 is at full power, 3413 MWt, with cross tie valve at closed position. With MSSV setpoint tolerance increased to 3%, Unit 2 LOCA analyses assumed a reduced core power, 3250 MWt, with cross tie valve at closed position. A reduction in power reduces the boil-off rate in the hot leg switchover calculation. A reduction in the boilwffrate results in the rate of boron build up also being reduced.

Therefore, the licensing basis hot leg switchover calculation for the Donald C. Cook Units 1 and 2 remains bounding.

LOCA H draulic Forci Functions The peak hydraulic forcing functions on the reactor vessel and internals occur very early in the large break LOCA transient. Typically, the peak forcing functions occur between 10 and 50 milliseconds (0.01 and 0.05 seconds) and have subsided well before 500 milliseconds (0.50 seconds). Any change in time associated with an increased MSSV setpoint tolerance would occur several seconds into the transient. Since the LOCA hydraulic forcing functions have peaked and subsided before the time at which the MSSV may actuate, the increase in the MSSV setpoint tolerance to 3% will not impact the LOCA hydraulic forcing functions calculation for Donald C. Cook Units 1 and 2.

LOCA Conclusio The effect of increasing the MSSV setpoint tolerance to 3% for Donald C. Cook Units 1 and 2 has been evaluated for each of the LOCA related analyses addressed in the UFSAR. For currently analyzed conditions, or for Unit 2 operation at a reduced power level of 3250 MWt when the high head cross tie valves are closed, it was shown that the 3% MSSV setpoint tolerance does not result in any design or Regulatory limit being exceeded. Therefore, with respect to the LOCA analyses, it can be concluded that increasing the MSSV setpoint tolerance to 3% for Donald C. Cook Units 1 and 2 will be acceptable from. the standpoint of the UFSAR accident analyses discussed in the safety

'valuation.

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SECI 91429, Revision 2 3.~

~

Containment Tnt ri Evaluation Relaxation of the Donald C. Cook Units 1 & 2 Technical Specification Main Steam Safety Valve setpoint tolerances from +1% to +3% do not adversely affect the short term or long term LOCA mass and energy releases and, subsequently, the related containment analyses. Since there is no impact on the main steaml inc break mass and energy release calculations, there is also no impact on that associated containment response analysis. The proposed change does not affect the normal plant operating parameters, system actuations, accident mitigating capabilities or assumptions important to the mass and energy release and containment analyses, or create more limiting conditions than those already assumed in the current analyses. Therefore, the conclusions presented in the Donald C, Cook UFSAR remain valid with respect to containment.

4. Steam Generator Tube Ru ture To demonstrate that an unreviewed safety question does not exist for the steam generator tube rupture (SGTR) event, the increased MSSV setpoint tolerance was evaluated for Donald C. Cook Units 1 and 2. The analysis for uprating to 3600 MWT considered up to 15% steam generator tube plugging for both Units 1 and 2. The limiting cases from this analysis were reevaluated for the increased MSSV setpoint tolerance. An increased steam generator tube plugging level of 20% was also considered at power levels of 3262 MWT for Unit 1 and 3425 MWT for Unit 2. The criteria stated in the UFSAR analysis for Donald C. Cook were used in establishing the continued applicability of the SGTR licensing basis safety analysis by demonstrating that the conclusions for SGTR UFSAR analysis remain valid.

An evaluation has been performed to determine the impact on the Donald C. Cook Units'GTR analysis of record for increased MSSV setpoint tolerance for all the cases with different steam generator tube plugging and power levels stated above. The primary thermal hydraulic parameters which affect the calculation of offsite radiation doses for a SGTR are the amount of radioactivity assumed to be present in the reactor coolant, the aniount of reactor coolant transferred to the secondary side of the ruptured steam generator through the ruptured tube, and the amount of steam released from the ruptured steam generator to the atmosphere. Thus, the calculated offsite radiation doses for an SGTR'for Donald C. Cook are dependent on these three factors.

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SECI 91<29, Revision 2 For the UFSAR SGTR analysis, the activity in the reactor coolant is based on an assumption of 1%

defective fuel, and this assumption will not be affected by the increased MSSV setpoint tolerance.

The two remaining factors are affected by the increased MSSV setpoint tolerance, and the evaluation was performed to quantify this effect.

To evaluate the effect of the increased MSSV setpoint tolerance on the Donald C. Cook SGTR analysis, the revised SG safety valve set pressure was lowered by 3% from 1080 psia to 1047.6 psia.

This resulted in a slightly higher equilibrium primary-to-secondary break flow (approximately 0.5%),

since there was an increase in the pressure differential between the RCS and secondary side assumed in the analysis. The steam released to the atmosphere subsequently increased (by approximately 0.2%) because of the lower pressure assumed for the main steam safety valves. The limiting cases, for all power levels and steam generator tube plugging levels considered, were at 3600 MVft.

The thyroid and whole body doses estimated for Units 1 and 2, based on the analyses described above, are bounded by those previously determined for the rerating program. The actual estimated dose factors (compared to the results of the rerating calculation) are as follows:

Unit f: thyroid 0.7, whole body 1.005 Unit 2: thyroid 0.99, whole body 0.98 Although the Unit 1 whole body dose exceeds the previous value by approximately 0.5%, this increase is well within the acceptable limit. Thus, the results and conclusion in the Donald C. Cook UFSAR that the offsite doses for an SGTR event would be within a small fraction of the 10CFR100 guidelines remains valid.

5. Com nent Performance The relaxation of the lift setpoint tolerance for the MSSVs at Donald C. Cook does not directly or indirectly involve mechanical component hardware considerations. Direct effects as well as indirect effects on equipment important to safety (ITS) have been considered. Indirect effects include activities which involve non-safety related equipment which may affect ITS equipment. Component hardware considerations may include overall component integrity, sub-component integrity, and the 9 I 429R2.wpf 25

SECI 91<29, Revision 2 adequacy of component supports during all plant conditions. An evaluation is not required to determine whether the condition alters the design, material, construction standards, function or method of performing the function of any ITS equipment.

6. S ste Evaluation The relaxation of the liftsetpoint tolerance for the MSSVs at Donald C. Cook as described would not affect the integrity of a plant auxiliary fluid system or the ability of any auxiliary system to perform its intended safety function.

7. Radiolo ical Evaluation The relaxation of the lift setpoint tolerance for the MSSVs at Donald C. Cook as described do not affect radiological concerns other than those identified above in Section III.4 or post-LOCA hydrogen production. The evaluation in Sections III.1 and GI.3 concluded that the existing mass releases used in the remaining offsite dose calculations (i.e., steamline break, rod ejection, locked rotor, and short-term & long-term LOCA) are still applicable,

8. Plant Ri k Anal activities affecti IP The relaxation of the liftsetpoint tolerance for the MSSVs at Donald C. Cook does not adversely affect the Individual Plant Examination /PE) for the plant. This test does not affect the normal plant operating parameters, system actuations, accident mitigating capabilities, operating procedures or assumptions important to the IPE analyses, or create conditions that would significantly affect core damage or plant damage frequency or the frequency of core damage initiating events. Therefore, the conclusions presented in the IPE remain valid.

9. Plant Risk Anal es ch es other than IPF relat The relaxation of the liftsetpoint tolerance for the MSSVs does not result in an increase in the probability of occurrence of accidents previously evaluated in the UFSAR. This proposed change to the Technical Specifications does not result in, an increase in the probability of occurrence of a 91429R2.wpf 26

SECI 91<29, Revision 2 malfunction of equipment important to safety or of equipment that could indirectly affect equipment important to safety.

10.

The relaxation of the lift setpoint tolerance for the MSSVs does not directly or indirectly involve electrical systems, components, or instrumentation considerations. Direct effects as well as indirect effects on equipment important to safety have been considered. Indirect effects include conditions or activities which involve non-safety related electrical equipment which may affect Class 1E, post accident monitoring systems, or plant control electrical equipment. Consideration has been given to seismic and environmental qualification, design and performance criteria per IEEE standards, functional requirements, and plant technical specifications with respect to all plant conditions. An evaluation is not required to determine whether the MSSV setpoint tolerance relaxation alters the design, configuration, qualification, or performance of safety related electrical systems or components. The MSSV setpoint tolerance relaxation has no potential for impact to the identification 1

of an unresolved safety question as it would relate to the safety related function of electrical systems of components.

11. Technical S ficatio A review of the Donald C. Cook Unit 1 and Unit 2 Technical Specifications was performed to address a change in the liftsetpoint tolerance for the Main Steam Safety Valves. The Technical Specification review, inclusive of Amendments 157 and 141 for Units 1 and 2, respectively.

Proposed markups are attached to this evaluation for both Unit 1 and Unit 2, and reflect changes to Table 4.7-1 and 3.7-4, respectively. A change to the basis for both units is also proposed and discusses the relationship between the J1% and J3% tolerances.

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SECL-91-429, Revision 2 IV. ASSESSMENT OF NO SAI'KFV UPON The relaxation in the lift setpoint tolerance for the MSSVs at Donald C. Cook Units 1 and 2 has been evaluated consistent with the requirements of 10CFR50.59 and does not involve an unreviewed safety question on the basis of the following justifications:

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

No. The +3% tolerance on the MSSV setpoint does not increase the probability of an accident previously evaluated in the UFSAR. There are no hardware modifications to the valves and, therefore, there is no increase in the probability of a spurious opening of a MSSV. The MSSVs are actuated to protect the secondary systems from overpressurization after an accident is initiated. 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 UFSAR would not be increased as a result of increasing the MSSV lift setpoint tolerance by 3% above or below the current Technical Specification setpoint value.

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

No. Based on the'discussions presented within, 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 UFSAR value by approximately 0.2%, the SGTR analysis indicates that

, the calculated doses are bounded by those determined for the rerating program which, in turn, are within a small fraction of the 10CFR100 dose guidelines. The evaluation also concluded that the existing mass releases used in the offsite dose calculations for the remaining transients (i.e., steamline break, rod ej ation) are still applicable. Therefore, based on the above, there is no increase in the dose consequences.

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SECL-91<29, Revision 2

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

No. As previously indicated in Section III.1, the Inadvertent Opening of a SG Relief or Safety Valve event is currently presented in the Donald C. Cook UFSAR (Section 14.2.5) and is bounded by the Steamline Break analysis. Increasing the as-found liftsetpoint 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 in the UFSAR is not created.

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

No. 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 liftsetpoint tolerance on the MSSVs will not adversely affect the operation of the reactor protection system, any of the protection setpoints, or any other device required for accident mitigation. Therefore, the probability of a malfunction of equipment important to safety previously evaluated in the UFSAR will not be increased.

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

No. As discussed in the response to Questions 2 and 4, there is no increase in the dose release consequences as a result of increasing the as-found liftsetpoint tolerance on the MSSVs as defined in the attached safety evaluation.

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SECI 91429, Revision 2

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

No. As discussed in Question 4, an increase in the as-found liftsetpoint tolerance on the MSSVs will not impact any other equipment important to safety. Therefore, the possibility of a malfunction of equipment important to safety different thari any already evaluated in the UFSAR will not be created.

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

No. As discussed in the a~ched safety evaluation, the proposed increase in the as-found MSSV lift setpoint tolerance will not invalidate the LOCA or non-LOCA conclusions presented in the UFSAR accident analyses. The new loss of load/turbine trip analysis concluded that all applicable acceptance criteria are still satisfied. For all the UFSAR non-LOCA transients, the DNB design basis, primary and secondary pressure limits, and dose limits continue to be met. Peak cladding temperatures remain below the limits specified in 10CFR50.46. The calculated doses resulting from a steam generator tube rupture event remain within a small fraction of the 10CFR100 permissible releases. Thus, there is no reduction in the margin to safety. Note that, as identified earlier, changes will be required to the plant Technical Specifications in order to implement the proposed change.

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SECL-91<29, Revision 2 SD The proposed change to main steam safety valve liftsetpoint tolerances from +1% to +3% has been evaluated by Westinghouse. The preceding analyses and evaluations have determined that operation with the MSSV setpoints within a J3% tolerance about the nominal values will have no adverse impact upon the licensing basis analyses, as well as the steamline break mass & energy release rates inside and outside of containment. In addition, it is concluded that the J3% 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 UFSAR remain valid.

Thus, based on the information presented above, it can be concluded that the proposed increase of main steam safety valve lift setpoint tolerances from J1% to J3% does not represent an unreviewed safety question per the definition and requirements defined in 10CFR50.59.

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

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SECL-91-429, Revision 2 VI. REFERENCES

1) Donald C. Cook Units 1 & 2 Technical Specifications through Amendments 157 and 141, respectively, 10/1/91.

2) ANSI/ASME BPV-I11-1-NB, "ASME Boiler and Pressure Vessel Code - Section III Rules for Construction of Nuclear Power Plant Components," ASME, 1983.

3) ANSUASME OM-1-1981, "Requirements for Inservice Performance Testing of Nuclear Power Plant Pressure Relief Devices," ASME, 1981.

4) "Donald C. Cook Units 1 & 2 Updated Final Safety Analysis Report (UFSAR), dated through July 1991.

5) ASME Steam Tables, Fifth Edition, 1983.

6)'urnett, T.W.T., et al., "LOFTRAN Code Description," WCAP-7907-P-A, June 1972.

7) Chelemer, H. et al ~,"Improved Thermal Design Procedure," WCAP-8567-P-A, February 1989.

8) Butler, J.C. and D.S. Love,"Steamline Break Mass/Energy Releases for Equipment Environmental Qualification Outside Containment," WCAP-10961-P, October 1985.

9) 90AE*-G4126 W/AEP2-0098 Transmittal regarding "Locked Rotor Dose Analysis for Donald C. Cook Unit 2 Cycles 8 & 9," 7/19/90.

10) Letter regarding AFW flow rates from R. B. Bennett of American Electric Power to J. N.

Steinmetz of Westinghouse Electric, 9/24/91.

11) WCAP-10054-P-A (Proprietary), WCAP-10081 (Non-Proprietary), Lee, H., et al.,

Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code, August 1985.

12) WCAP-12135, Donald C. Cook Nuclear Plant Units 1 and 2 Rerating Engineering Report, Vol. 1, September 1989.

91429R2.wpf 32

SECL-91<29, Revision 2 TABLE 3 UNIT I TURBINE TRIP SEQUENCE Accident Time sec Without pressurizer control Turbine trip, loss of main 0.0 (minimum reactivity feedback) feedwater flow High pressurizer pressure 77 reactor trip setpoint reached Rods begin to drop 9.7 Peak pressurizer pressure 10.5 occurs Minimum DNBR occurs Without pressurizer control Turbine trip, loss of main 0.0 (maximum reactivity feedback) feedwater flow High pressurizer pressure 7.9 reactor trip setpoint reached Rods begin to drop 9.9 Peak pressurizer pressure 10.5 occurs Minimum DNBR occurs With pressurizer control Turbine trip, loss of main 0.0 (maximum reactivity feedback) feedwater flow feedback)'vent Peak pressurizer pressure 10.0 occurs Low-low steam generator 47.1 water level reactor trip setpoint reached Rods begin to drop 49.1 Minimum DNBR occurs With pressurizer control Turbine trip, loss of main 0.0 (minimum reactivity feedwater flow High-pressurizer pressure 12.4 reactor trip setpoint reached 91429Rz.wp f 33

SECL-91<29, Revision 2 TABLE 3 (continued)

UNIT I TURBINE TRIP SEQUENCE Accident Event T~ime sec Rods begin to drop 14.4 Peak pressurizer pressure 16.0 occurs Minimum DNBR occurs 15.5

• DNBR does not decrease below its initial value.

91429R2.wpf 34

SECL-91<29, Revision 2 TABLE 4 UNIT 2 TURBINE TRIP SEQUENCE OF EVENTS T~ime eee Accident Event Inixed full core core Without pressurizer control Turbine trip, loss of main 0.0 0.0 (minimum reactivity feedback) feedwater flow High pressurizer pressure 5.5 7.5 reactor trip setpoint reached Rods begin to drop 7.5 9.5 Peak pressurizer pressure 9.5 11.0 occurs Minimum DNBR occurs Without pressurizer control Turbine trip, loss of main 0.0 0.0 (maximum reactivity feedback) feedwater flow High pressurizer pressure 5.5 7.6 reactor trip setpoint reached Rods begin to drop 7.5 9.6 Peak pressurizer pressure 9.0 10.0 occurs Minimum DNBR occurs

• DNBR does not decrease below its initial value.

91429R2.wp f 35

SECL-91<29, Revision 2 TABLE 4 (continued)

UNIT 2 TURBINE TRIP SEQUENCE OF EVENTS Time ec Accident Event full core core With pressurizer control Turbine trip, loss of main 0.0 0.0 (maximum reactivity feedback) feedwater flow Peak pressurizer pressure 7.0 7.5 occurs Low-low steam generator 60.1 52.8 water level reactor trip setpoint reached Rods begin to drop 62.1 54.8 Minimum DNBR occurs With pressurizer control Turbine trip, loss of main 0.0 0.0 (minimum reactivity feedback) feedwater flow High pressurizer pressure 10.6 11.2 reactor trip setpoint reached Rods begin to drop 12.6 13.2 Peak pressurizer pressure 13.5 14.5 occurs Minimum DNBR occurs 14.5 15.0

• DNBR does not decrease below its initial value.

91429R2.wp f 36

SECI 91-429, Revision 2 TABLE 5 CURREN'I'ICENSING BASIS STEAM LINE SAFETY VALVES PER LOOP Safety Setpoint Percent Accumulation Flowrate Acc .

Valve Accumulation 1A 1065 10.0 1171.5 857690 1B 1065 10.0 1171.5 857690 2A 1075 8.98 1171.5 857690 2B 1075 8.98, 1171.5 857690 1085 7.97 1171.5 857690 The rated valve capacity at full accumulation pressure was calculated as follows:

51.5 x A x K x P = Actual Flowrate where:

A = Valve orifice area = 16 in'

= Coefficient of discharge = 0.975 P = Pressure (psia) at accumulation pressure The above actual fiowrate is reduced by 0.9 to get the valve rated capacity.

91429R2.wpf 37

SECI 91<29, Revision 2 TABLE 6 MSSV SETPOINT INCREASE STEAM LINE SAFEIV VALVES PER LOOP Safety Setpoint Pressure Percent Accumulation Flowrate Acc Valve ccumulation 1A 1096.95 3.0 1129.86 827585.6 1B 1096.95 3.0 1129.86 827585.6 2A 1107.25 3.0 1140.47 835257.2 2B 1107.25 3.0 1140.47 835257.2 1117.55 3.0 1151.08 842928.9 The rated valve capacity at full accumulation pressure was calculated as follows:

51.5 x A x K x P'= Actual Flowrate where:

A = Valve orifice area = 16 in K = Coefficient of discharge = 0.975 P = Pressure (psia) at accumulation pressure The above actual flowrate is reduced by 0.9 to get the valve rated capacity.

91429R2.wpf 38

SECL-91-429, Revision?

PRESSURE, LOW TEMPERATURE Current MSSV Licensing Setpoint Basis Increase License Core Power'MWt) 3588'.32 3250 Total Peaking Factor, F< 2.32 Axial Offset (%) +30 +30 Hot Channel Enthalpy Rise Factor, F 1.55 1.55 Maximum Assembly Average Power, P~ 1.433 1.433 Fuel Assembly Array 15 15 OFA Accumulator Water Volume (ft') 946 946 Accumulator Tank Volume (ft') 1350 1350 Minimum Accumulator Gas Pressure, (psia) 600 600 Loop Flow (gpm) 354000 354000 Vessel Inlet Temperature (F) 509.89 513.23 Outlet Temperature 'essel 581.71 578.57 (F)'CS Pressure (psia) 2100 2100 Steam Pressure 564.36 596.48 (psia)'team Generator Tube Plugging Level (%) 15 15 Maximum Refueling Water Storage Tank Temperature (F) 120 120 Maximum Condensate Storage Tank Temperature (F) 120 120 Fuel Backfill Pressure (psig) 275 275 Reactor Trip Setpoint (psia) 1860 1860 Safety Injection Signal Setpoint (psia) 1715 1715 Safety Injection Delay Time (sec) 27 27 Safety Injection Pump Degradation (%) 10 10 Charging Pump Flow Imbalance (gpin) 10 25 HHSI Cross Tie Valve Position Closed Closed Signal Processing Delay and Rod Drop Time (sec) 2.0 4,4 Reactor Coolant Pump Delay Time (sec) 4,4 4,4 Main Feedwater Isolation Delay Time (sec) 0.0 0.0 Main Feedwater Valve Closure Time (sec) 8.0 8.0 Auxiliary Feedwater Enthalpy Delay Time (sec) 272 60'able Main Steam Safety Valve Setpoint (psia) 5 Table 6 Two percent is added to this power to account for calorimetric error.

A safety evaluation for 25 gpm charging flow imbalance limits operation with HHSI cross tie valve closed to 3250 MWt.

Value is based on 102% core power, main coolant pump heat neglected, and best estimate Tavg.

A safety evaluation was performed to account for a auxiliary feedwater enthalpy delay of 272 seconds.

9l429R2.wpf 39

SECI 91-429, Revision 2 TABLE 7a Initial Input Parameters for the Small Break LOCA Analysis Current MSSV Licensing Setpoint Increase License Core Power'MWt) ~Bas'588'.32 3250 Total Peaking Factor, F<. 2'.32 AxM Offset (%) +30 +30 Hot Channel Enthalpy Rise Factor, P~ 1.55 1.55 Maximum Assembly Average Power, P~ 1.433 1.433 Fuel Assembly Array 15 X 15 0 FA Accumulator Water Volume (ft') 946 946 Accumulator Tank Volume (ft ) 1350 1350 Mirumum Accumulator Gas Pressure, (psia) 600 600 Loop Flow (gpm) 354000 354000 Vessel Inlet Temperature 509.89 513.20 581.71 578.44

('F)'essel Outlet Temperature ('F)'CS Pressure (psia) 2100 2033 Steam Pressure 564.36 596.11 (psia)'team Generator Tube Plugging Level (%) 15 15 Maximum Refueling Water Storage Tank Temperature ('F) 120 120 Maximum Condensate Storage Tank Temperature ('F) 120 120 Fuel Backfill Pressure (psig) 275 275 Reactor Trip Setpoint (psia) 1860 1860 Safety Injection Signal Setpoint (psia) 1715 1715 Safety Injection Delay Time (sec) 27 27 Safety Injection Pump Degradation (%) 10 10 Charging Pump Flow Imbalance (gpm) 10 25 HHSI Cross Tie Valve Position Closed Closed Signal Processing Delay and Rod Drop Time (sec) 2.0 4.4 Reactor Coolant Pump Delay Time (sec) 4.4 4.4 Main Feedwater Isolation Delay Time (sec) 0.0 0.0 Main Feedwater Valve Closure Time (sec) 8.0 8.0 Auxiliary Feedwater Total Delivery (gpm) 1258 750 Auxiliary Feedwater Delivery Delay Time (sec) 60'able 60'able Main Steam Safety Valve Setpoint (psia) 1 2 Accumulator Temperature ('F) 120 130 Two percent is added to this power to account for calorimetric error.

A safety evaluation for 25 gpm charging fiow imbalance limits operation with HHSI cross tie valve closed to 3250 MWt.

Value is based on 102% core power, main coolant pump heat neglected, and best estimate TAvo.

. A safety evaluation was performed to account for an auxiliary feedwater enthalpy delay of 272 seconds.

Enthalpy delay computed internally based on AFW flow rate and 75 ft'urge volume.

40

SECI 91-429, Revision 2 TABLE 8 LOW PRESSURE, HIGH TEMPERATURE Current MSSV Licensing Setp oint Basis Increase License Core Power'MWt) NA 3250 Total Peaking Factor, F< NA 232 Axial Offset (%) NA +30 Hot Channel Enthalpy Rise Factor, F NA 1.55'.433 Maximum Assembly Average Power, Pu NA Fuel Assembly Array NA 15X15 OFA Accumulator Water Volume (ft') NA 946 Accumulator Tank Volume (ft') NA 1350 Minimum Accumulator Gas Pressure, (psia) NA 600 Loop Flow (gpm) NA 354000 Vessel Inlet Temperature (F) NA 543.63 Outlet Temperature (F)'CS

'essel NA 606.79 Pressure (psia) NA 2100 Steam Pressure (psia)'team NA 793.90 Generator Tube Plugging Level (%) NA 15 Maximum Refueling Water Storage Tank Temperature (F) NA 120 Maximum Condensate Storage Tank Temperature (F) NA 120 Fuel Backfill Pressure (psig) NA 275 Reactor Trip Setpoint (psia) NA 1860 Safety Injection Signal Setpoint ('psia) NA 1715 Safety Injection Delay Time (sec) NA 27 Safety Injection Pump Degradation (%) NA 10 Charging Pump Flow Imbalance (gpm) NA 25 HHSI Cross Tie Valve Position NA Closed Signal Processing Delay and Rod Drop Time (sec) NA 4.4 Reactor Coolant Pump Delay Time (sec) NA 4.4 Main Feedwater Isolation Delay Time (sec) NA 0.0 Main Feedwater Valve Closure Time (sec) NA 8.0 Auxiliary Feedwater Enthalpy Delay Time (sec) NA 272 Main Steam Safety Valve Setpoint (psia) NA Table 6 1 Two percent is added to this power to account for calorimetric error.

2 A safety evaluation for the low pressure, high temperature operating condition was performed in the licensing basis analysis.

3 Value is based. on 102% core power, main coolant pump heat neglected, and best estimate Tavg.

91429R2.wpf 41

SECL-91<29, Revision 2 TABLE 9 LOW PRESSURE, HIGH TEMPERATURE Current MSSV Licensing Setp oint Basis Increase License Core Power'MWt) 3413 3250 Total Peaking Factor, Fz 2.34 2.357 Axial Offset (%) +30 +13 Hot Channel Enthalpy Rise Factor, F 1.644 1.666 Maximum Assembly Averag e Power, Pn 1.519 1.46 Fuel Assembly Array 17 17V5 Accumulator Water Volume (fP) 946 946 Accumulator Tank Volume (ft') 1350 1350 Minimum Accumulator Gas Pressure, (psia) 600 600 Loop Flow (gpm) 354000 354000 Vessel Inlet Temperature (F) ~ 544.41 544.41 Vessel Outlet Temperature 610.19 610.19 (F)'CS Pressure Including Uncertainties (psia) 2100 2100 Steam Pressure (psia) 807.03 807.03 Generator Tube Plugging Level (%)

'team 15 15 Maximum Refueling Water Storage Tank Temperature (F) 120 120 Maximum Condensate Storage Tank Temperature (F) 120 120 Fuel Backfill Pressure (psig) 275 275 Reactor Trip Setpoint (psia) 1860 1860 Safety Injection Signal Setpoint (psia) 1715 1715 Safety Injection Delay Time (sec) 27 27 Safety Injection Pump Degradation (%) 10 10 Charging Pump Flow Imbalance (gpm) 25 25 HHSI Cross Tie Valve Position Closed Closed Signal Processing Delay and Rod Drop Time (sec) 4.7 4.7 Reactor Coolant Pump Delay Time (sec) 4.4 44 Main Feedwater Isolation Delay Time (sec) 0.0 2.0 Main Feedwater Valve Closure Time (sec) 8.0 6.0 Auxiliary Feedwater Enthalpy Delay Time (sec) 349 349 Main Steam Safety Valve Setpoint (psia) Table 5 Table 6 1 Two percent is added to this power to account for calorimetric error.

2 Value is based on 102% core power, main coolant pump heat neglected, and best estimate Tavg.

91<29R2.wpf

SECI 91<29, Revision 2 TABLE 10 TIME SEQUENCE OF EVENTS LPLT LPLT LPHT LPHT Event w/ MSSV w/o MSSV w/ MSSV w/o MSSV Break Occurs 0 0 0 0 Reactor trip signal 11.23 11.23 13.54 13.54 Safety injection signal 19.28 19.28 22.42 22.42 Start of safety injection signal 46.28 46.28 49.42 49.42 Loop seal venting 643.4 644.7 601.8 608.3 Loop seal core uncovery NA NA NA NA Loop seal core recovery NA NA NA NA Boil-offcore uncovery 1139.2 1077.3 1073.4 1057.8 Accumulator injection begins 1730.0 1751.0 1647.8 1695.8 Peak clad temperature occurs 1935.5 1831.4 1872.3 1824.7 Top of core covered NA NA NA NA SI flow rate exceeds break flow rate 1988 2024 2293 2284 LPLT is low pressure, low temperature operating condition.

LPHT is low pressure, high temperature operating condition.

W/ MSSV is main steam safety valve setpoint tolerance increase case at 3250 MWt core power.

W/0 MSSV is licensing basis main steam safety valve setpoint tolerance case at 3250 MWt core power.

91429R2.wpf 43

SECL-91-429, Revision 2 TABLE 10a TIME SEQUENCE OF EVFATS Time (seconds)

LPLT LPLT w/MSSV w/MSSV Event 3 inch Break 2 inch Break Break Occurs 0.0 0.0 Reactor trip signal 8.64 19.03 Safety injection signal 17.13 37.11 Start of safety injection 44.13 64.11 Start of auxiliary feedwater delivery 68.6 79.1 Loop seal venting 592 1390 Loop seal core uncovery N/A N/A Loop seal core recovery N/A N/A Boil-offcore uncovery 984 2312 Accumulator injection begins 1680 N/A Peak clad temperature occurs'op 1890 4042 of core covered N/A N/A SI flow rate exceeds break flow rate 1890 4091 LPLT is low pressure, low temperature operating condition.

W/ MSSV is main steam safety valve setpoint tolerance increase case at 3250 MWt core power.

SECL-91-429, Revision 2 TABLE 11 SUMMITRY OF RFSULTS LPLT LPLT LPHT LPHT w/ MSSV w/o MSSV w/ MSSV w/o MSSV NOTRUMP Peak Clad Temperature ('F) 1853.7 1772.9 1837.7 1710.3 Peak Clad Temperature Location (ft) 11.75 11.75 11.75 11.75 Peak Clad Temperature Time (sec) 1935.5 1831.4 1872.3 1824.7 Local Zr/H,O Reaction Maximum (%) 3.47 2.47 3.13 1.82 Local Zr/H,O Reaction Location (ft) 11.75 11.75 11.75 11.75 Total Zr/H,O Reaction (%) < 1.0 < 1.0 <1.0 <1.0 Rod Burst None None None None Burst and Blockage Penalty ('F) 25 15 16 15 Total Peak Clad Temperature ('F) 1878.7 1787.9 1853.7 1725.3 LPLT is low pressure, low temperature operating condition.

LPHT is low pressure, high temperature operating condition.

W/ MSSV is main steam safety valve setpoint tolerance increase case at 3250 MWt core power.

W/0 MSSV is licensing basis main steam safety valve setpoint tolerance case at 3250 MWt core power.

91429R2.wpf 45

SECL-91-429, Revision 2 TABLE 11a

SUMMARY

OF RESULTS LPLT LPLT w/MSSV w/MSSV 3 inch Break 2 inch Break NOTRUMP Peak Clad Temperature ('F) 1951 1833 Peak Clad Temperature Location (ft) 12.0 12.0 Peak Clad Temperature Time (sec) 1890 4042 Local Zr/H,O Reaction Maximum (I) 5.06 3.75 Local Zr/H~O Reaction Location (ft) 12.0 12.0 Total Zr/H,O Reaction (%) 0.568 0.397 Rod Burst None None Burst and Blockage Penalty ('F) 117 15 Total Peak Clad Temperature ('F) 2068 1848 LPLT is low pressure, low temperature operating condition.

W/ MSSV is main steam safety valve setpoint tolerance increase case at 3250 MWt core power.

46

SECI 91<29, Revision 2 TABLE 12 TIIKE SEQUENCE OF EVI<22lTS Time Event LPHT LPHT w/ MSSV ~w/0 MS V Break Occurs 0 0 Reactor trip signal 11.01 11.01 Safety injection signal 20.92 20.92 Start of safety injection signal 47.92 47.92 Loop seal venting 620.0 627.2 Loop seal core uncovery NA NA Loop seal core recovery NA NA Boil-offcore uncovery 620.0 627.2 Accumulator injection begins 1604.3 1631.7 Peak clad temperature occurs 1691.0 1720.6 Top of core covered NA NA SI flow rate exceeds break flow rate 1683.0 1984.0 LPHT is low pressure, high temperature operating condition.

W/ MSSV is main steam safety valve setpoint tolerance increase case at 3250 MWt core power.

W/0 MSSV is licensing basis main steam safety valve setpoint tolerance case at 3413 MWt core power.

91429R2.wp f 47

SECI 91429, Revision 2 TABLE 13 SUlVPdARY OF RESULTS LPHT LPHT w/ MSSV w/o MSSV NOTRUMP Peak Clad Temperature ('F) 1955.9 1947.1 Peak Clad Temperature Location (ft) 11.75 11.75 Peak Clad Temperature Time (sec) 1691.0 1720.6 Local Zr/H,O Reaction Maximum (%) 4.26 4.83 Local Zr/H>0 Reaction Location (ft) 11.75 11.75 Total Zr/H,O Reaction (%) <1.0 <1.0 Rod Burst None None ArtificialLeak-By Penalty ('F) 12 12 Burst and Blockage Penalty ('F) 157 143 Total Peak Clad Temperature ('F) 2124.9 2102.1 LPHT is low pressure, high temperature operating condition.

W/ MSSV is main steam safety valve setpoint tolerance increase case at 3250 MWt core power.

W/0 MSSV is licensing basis main steam safety valve setpoint tolerance case at 3413 MWt core power.

91429R2.wpf 48

SECL-91<29, Revision 2 FIGU1H~5 91429R2.wpf 49

W QQ RSIA 24OO PSIA 68 1840

>SIA

'000 i PsaA 2100 x PSIA 45

~

~ gglgQTOl VA1.VES O'EN 578 575 598 .. 595 5" 8 'l5 688 685 613 615 628 625 638 avg ( P:

eaaaaa p+ Nominal Tave ~ 578.7'F Core Ltmits .'(ominal PI.assure ~ 2100 ps.'a OONALO C. COOK UNIT 1 FIGURE la ILLUSTRATION OF OVERTEHPERATURE ANO. OVERPOWER OELTA T PROTECTION i

'I

75 OPaT 1922 2250 PSIA PSIA 65 04 2000 PSIA 2400 PSlA

<5 STEAN GENERATOR SAPPY VALVES OPEN 568 56S 578 575 58B 585 5'%'tS 688 685 618 615 628 625 T eve leF')

---

OTaT Protectfon Lfnes Cars Thsrtasl Ssfsty Ltsfts Nominal Vessel Average Teaperature 576'F Noafnal Pressurfzer Pressure 2250 psfa DONALD C COOK UNIT 2 (MIXED CORE)

FIGURE 1b ILLUSTRATION OF OVERTEMPERATURE ANO OVERPOWER DELTA T PROTECTION

OPaT 1922 73~ PSIA 2400 '.

PSIA 2000 53 PSIA 2250 STGN GENERATOR PSIA SAFETY VALVES OPEN 575 S88 585 5 I8 S~S 688 685 618 6 I5 628 625 ai3 nvg (~F'!

---

OTaT Protect)on Lines Core Therssal Safety Lfeits Nominal Vessel Average Temperature 5S1.3'F Nominal Pressurizer Pressure 2100 psia.

DONALD C. COOK UNIT 2 (FULL V5 CORE)

FIGURE Ic ILLUSTRATION OF OVERTEHPERATURE AND OVERPOWER DELTA T PROTECTION

h

~ v VV I

CC

~ 4h V v p l

'v4 I

I A "lCC C

." 300.

l 900.

lo. 20. 30. 40. 50. 60. ~C, 80. 90.

T MK (SEC~

2300.

F800.

>600 1~00

'4 1200 Jl IQOO.

0. 10. 20. 30. 40.

T ME 50 '0.

(SEC)

70. 80. 90. >00.

DONALD C. COOK UNIT I FIGURE 2 TURBINE TRIP EVENT 'WITHOUT PRESSURE CONTROL, HINUHUH REACTIVITY FEEDBACK

~~

rD ~

z I

I I

I i

i I

4

~ ~

Z 10 20 ic 40 T ~E 53 60 (SEC) 70 80:C 4 5 5

1.5 10 20 30 40 50 60 70 80 9C 1'K (SEC'ONALD C. COOK UNIT I FIGURE 3 TURBINE TRIP. EVENT WITHOUT PRESSURE CONTROL, HINUHUM REACTIVITY FEEDBACK

560 5~0 520 i 530 56C 5'0 520 500 0 10 20 3C <0 50 60 70 80 iC lC T 0= (SEC)

EGG'80 560 5<0 52G 500 2

560 560 i 5<0 520 500 70 90 t"3 0 10 20 30 40 50 60 SG v=

(SEC,'ONALD C. COOK UNIT I FIGURE 4 I TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, MINUMUM REACTIVITY FEEDBACK .

I

~

CC 1

1

'JCO 9CC.;

9CG.;

700.

50C.

500

0. IO. 20. 30. 40. 50. 60. 70. 90. 90. lQQ.

T uE (SEC) 400 tQ 350 300 250 200 150 C',

100 50 0

-50 10 20 30 40 50 50 70 dO 90 'CO Ti & (SEC)

DONALD C. COOK UNIT I FIGURE 5 I I

TURSINE TRIP EVENT WITHOUT PRESSURE CONTROL, HININN REACTIVITY FEEDBACK

35 sp 25 20 15 OC tv ip 5Ul 0

-5

-10 0 , 10 20 30 40 50 50 70 80 90 tCO TlhtK (SEC)

OONALO C. COOK UNIT 1 FIGURE 6 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, HININN REACTIVITY FEEDBACK

OC

<OC a hAQ V

n 1 i~]

V C

'30C t800. io. 50.

Io. 20. 30. 60. ~0. 50. 90. <OC.

T:~E (SEC)

"300.

1900

>500 ac cr i 400

>200.

Jl

>300.

0. 10. 20. JO. 40. 50. 60. 70. 60. 90. IOC.

ri~K (sEc)

OONALD C. COOK UNIT I FI6URE TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL,

NXINN REACTIVITY FEEOBACK

0.

10 20 30 +0 50 60 70 d0 90 lCQ T vK (SEC,'

2.5 1.5 1.

0 10 20 30 40 50 60 70 d0 90 tCQ TisK (SEC)

DONALD C. CMK UNIT I FIGURE 8 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, HAXII%N REACTIVITY FEEDBACK

66G 620 ~

~ V

!30 560 dr.o 520 500 tO 20 SO iO 50 do Io 80 90 r vc (sac)

>oo 660 660 6<o 620 500 8

5do seo 5~0 520 500 to 20 30 40 50 do 70 80 90 too ritz (sec)

ONALO C. COOK UNIT I FISNE TURBINE TRIP EVENT ltITH0UT NESSVRE CONTROL,

'NXINN REACTIVITY FEEDBACK

~

nC 2C

'A '.

300 A

300 I

'J) 3CC,;

700.

500.

500

0. 10. 20. 30. 40. 50. 60. 70. 80. 90. 100.

TlMK (SEC) 400 350 300 250 200 150 100 50 0

-50 0 tQ 2Q 30 40 50 50 70 d0 90 100 TIME (SEC)

DNALD C. CXK UNIT I FIGURE 10 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NXINPl REACTIVITY FEEDBACK

25 20 tQ 15 10 ac QC A4 5

-5

-10 0 10 ~

20 30 40 50 60 , 70 SO 90 1CO TlsK (SEC) 0ONALP C. COOK UNIT 1 FIGURE 11 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

a o a 4ag ~

"500 n

50C 5 h j 40C

" 'CC I

"2OC n

'OC 2300 1900.

1800

0. 10. 20. 30. io. 50. do. 70. 40. 80 . iCC tivK (SKC) 2300.

isoo.

t doo.

c >400.

1200.

n n

t 000.

)0. io.

20, go.

T ill 50. (5CC)do. 70 ~ 80, 90. ~OC.

OQWLD C. COOK NIT 1 FIQNE 12 mam TaIe EVEN VITH PRESSVRE CNTROL ~

NXINN REACTIVITY FEEoMCK

8 5

2 0 10 20 30 <0 50 d0 10 80 90 T>MK (SEC) 4 5

. 3.5 2.5 10 20 30 40 50 60 10 80 9G Tlirt (5KC)

ONE C. COOK . NIT I FIGNE 13 TtWSINE TRIP EVENT 'KITH PRESSNE CONTROL, NXINN REACTIVITY FEEDBACK

580 560 520 cBS

~60 540 520 500 lO 20 30 +0 50 50 VO T'Mg (SKC) 700 560 5iQ 520 500 2

580 560 540 10 20 30 40 50 80 10 d0 9G tCS TIIC (SEC)

XNALD C. COOK UNIT 1

, FI6URE 14 TUNM TRIP EVBIT QlTH PRESSNE CONTROL, NX1NN REACTIV?TY FEEDBACK

I IQQ 1500.

300.

BOO.

700:

600.

500

0. 10. 20. 30. 40.. 50. 60. 70. 60.

TlhlK (SEC) 400 350 I

3OO 250 200 150 100 I

50 0

0 10 20 30 40 50 60 70 80 90 100 T1QK (SEC)

OelALD C. COOK UNIT 2 (FULL YS CORE)

FIGURE 15 TURBINE TRIP EVENT WITH PRESSURE CONTROL, NXINN REACTIYITY FEEOBACK

25 20 Ql 1 5 10 5

-10 0 10 20 30 40 50 50 70 d0 90 100 Ti~K (SEC)

ONALG C. COOK UNIT 2 (FULL VS CORE)

FIGURE 16 TURBINE TRIP EVENT WITH PRESSURE CONTROL, NXINtw REACTIVITY FEEOBACK

2500.

2400.

nn

"~"C'v

'n 2OOO.

l 800.

l d00,

0. l0 . 20. 30 . '0,T<~g 50 d0 (SKC) 70 g0. 90. laC.

2300.

l800.

1 d00.

1400.

I 200.

l 000, 800. 50, 70. So 90 lo lo 20 30. 40. 50.

(SEC)

OONLD C. COOK UNIT 1 FI6NE 17 TURSINE TRIP EVENT MITH PRESSURE CONTROL, NINNN REACTIVITY FEEOBACK

2 5

a 4

x 2 0 10 20 30 40 50 do 70 do )C" 1'iuK 9C (SKC) 5 2.5 2 ~

0 10 20 30 io 50 00 70 do M iOO TiitE (SEC)

ONNLD C. COOK UNIT I FI6NE 18 TNSINE TRIP EVENT 'WITH PRESQNE CONTlSL, NINNN REACTIVITY FEEDBACK

56C' 5@i 52" 5~0 5

560 s~c 520 500 10 20 30 40 50 60 TO 80 'C" 9C T'lK (SEC) 700 680 560 6<0 525 600 580 51 555 5<0 520 4 14 20 30 40 50 T 1 IC ~

(SEC)

DNQLD'C. CON NIT I FINRE- Ig TNSINE TRIP EVENT WITH PRESSVRE CONTROL, NINNN REACTIVITY FEEDBACK

1000.

900.

800.

700.

500.

500

0. lp, 20, 30. 40. 50. dp. 70. 80. 90. 100.

TiuK (SEC) 500 CJ 4J Vl

<00 4

300 200 l00 0

-100 0 10 20 30 40 50 dp 70 80 90 100 TiVK (SEC) 00NALO C. CON NIT I FIGURE 20 TURBINE TRIP EVENT WITH PRESSURE CONTROL, NININN REACTIVITY FEEDBACK

30 25 20

)5 10 QC 5

tA ac 0 CL

-t0 0 I 0 20 30 40 50 60 70 80 90 100 Ti& (SEC)

ONNLD C. CON UNIT I FI6URE 21 TURBINE TRIP EVENT WITH PRESSURE CONTROL, NININN REACTIVITY FEEDBACK

2500.

n 250C.

5

<OC

~CO x

'V

2QC.

2100.

" 00 F900.

1/00

0. t0. 20. 30. 40. 50. 50. 70. 50. 9Q, )GG t ~c (sac>

2000.

1800.

1d00.

x

[400.

1200.

1300.

0. 10. 20. 30. 40. 50. 80. 10. 80. 90. t00.

re% (5')

OINED C. COOK NIT 2 (NIXEO CORK)

FIQNK 22a TNSNE TRIP EVENT ltITHOUT PRESSNE CONTROL, NINNY REhCTIVITY FKEDBAC<

50C n

< c,PC

'CC I

~

\+

o e rV yA 43 tOC C

""OC

>90C.

1800 0 ~ le 20 '0 ~ <0 ~

~ MK

50. 60.

(SEC)

70. <0. g0. ~PC "30C tSOC.

l 500.

t 40C.

I 200.

1300.

0. t0. 20. 30. 40. 50. 60. 70. 50. 90. lOC (MC) tOMLD C. CON NIT 2 (fULL V5 CONK) fIQNK 22b TlNSINE TRIP EV9fT VITHOUT PRKSSlNK CONTROL, NINNN REKTIVITY FEEDSACK

C c 5 x 2 0

0 l0 20 30 ~0 50 50 >0 80 90 ~Co

'Tissu (SKC) 2.5 2.2 t.d l.2 <0 50 50 . 10 iCa 4 >0 20 30 50 .SO Tilg (SEC)

OOOO C. COOK NIT 2 (NIXEO CORE)

FICNE 23a TlNSINE TRIP EVBIT WITHOUT PRESQNK CSlTROf.,

NINNN REhCTIVITY FEEO84<<

tO ZO 3O .O a 6O (sec) to 20 30 40 50 60 70 80 K iCQ 7:~K (SEC) tONU) C; COOK UNIT 2 (FVLl, N CORE)

FINRE 23b TVRIINE TRIP EVENT itITHOUT PRESSURE @NIAL, NINNN REACTIVITY FEEDBACK

0 560 diQ 520 I

530 560 5cQ 520 500 Q l0 20 30 40 50 60 70 80 9Q

~

Ti~E (SEC) 700 680 660 6+0 620 600 9

MQ MO 5<0

]4 20 '0 40 Ti &

50 d0 (SEC)

>0 60 90 DONALD C. CNX NlT 2 (NlXED CORE)

FENRK 24a TNSlNE TRlP EVENT QlTHOUT PRESQNE CONTROL, MINN% REACT[VlTY FEEOBACK

53 I I

c60 5ao 5ZQ 5:c

.'30 c6 szo 500 O lO ZO SO 4O 50 . 6O rO ao aC .Cg r QK (SEC)

.00 Sao 560 5io 520 500 580 I 560 5co 520 0 ~0 20 30 iO 50 60 70 40 SO iCO r w (sKc)

ONED C. COOK NIT 2 (RKL V5 CORK)

FIQNE 24b TURSINE TRIP EVENT WITHOUT NESSNE COKTROL, NINNN REACTIVITY FEEDBACK

'20C 1000.

z 300.

BQO.

o 700.

600.

500.

0. Io. 20. 30. <0. 50. 60. 70. 60. 9Q. IQQ.

TIME (SEC) 400 350 zoo 250 200 150 100 50 0

0 t0 20 30 40 50 60 70 80 90 >00 7 i & (SEC)

DNALD C. COOK NIT 2 (MIXED CORE)

FIGURE 25a TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, MINN@ REACTIVITY FEEDBACK

oc P 11QQ.

100.

300.

BCQ.

700.

500.

500

0. 10. 20. 30. 40. 50. SO. 70. 80. 90. 1OO.

TIME (SEC) 400 rn 350 300 250 2OO 150 100 50 0

-50 10 20 30 <0 50 do 70 80 90 100 TiME (SEC) 00NLD C. 'COOK UNIT 2 (FULL VS CORE)

FIGURE 251 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NINNN REACTIVITY FEEOBACK

40 30 25 20 15 10 5Vl 0

-5

-10 0 10 20 30 40 50 d0 70 50 90 )QQ TivK (SEC)

DONALO C. COOK UNIT 2 (MIXED CORK)

FIGURE 264 TURBINE TRIP EVENT WITHOUT

'RESSURE CONTROL,

.NINLNN REACTIVITY FEEOBACK

40 35 30 25 20 15 (Y

10 5

0

-5

-10 0 10 20 30 40 50 50 70 d0 90 100 Ti~E (SEC)

DONALD C. COOK UNIT 2 (FULL VS CORE)

FIGURE 26b TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, MIHUNN REACTIVITY FEEDBACK

tV "50C n

"50C

=~OC i vs

~ 1hP aavlo n

2 lQC C

2300.

1300.

1500.'0.

10. 20. 30. 40. 50. 50 70. dO. 90. 100 Ti IE (SEC) 2'300.

1800.

le00.

ct 1400.

'V 1200.

'1 000 .

800.

0. 10. 20. JO. 40. $ 0. 60. 70. 80. 90. 100.

Ti~K fMC) 004lLD C. CON NIT 2 (MIXED CORE)

FIQURE 27a TURBINE TRIP'VENT M?THOUT PRESSURE CONTROL, NXINPI REACTIVITY FEEDBACK

OA A

~4 "5GC n

"504 C

I hc a%%

2 tQC "300

>900.

>500

0. t0. ZQ. 30. 44. 50. d0 94 >00

(~C)

4. 300 I/00.

i 500.

'00.

> 200.

I 300.

0. 10. 20. 30. 44, 50. d0. 70. 60. 90. F00 T sK (MC)

'ONAN C. COOK UNIT 2 (FULL V5 CORE)

FI6NE 27b TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, .

NXISN REACTIVITY FEEDBACK

0.

l0 20 30 40 50 50 70 d0 9Q T~vE (SKC) 2.d 2.6 2.4 j2, 10 20 30 40 50 d0 70 d0 90 lC" (sac)

OONLD C. COOK UNIT 2 (NIXEQ CORE)

FIQNE 28a TVRSINE TRIP EVENT WITHOUT PRESQNE CONTROL, NXINN REACTIVITY FEEDBACK

C IQ 2Q 30 +0 50 60 70 I50 9C 'CQ T: MK (SKC) 5 5 2 5

>.5

l. O tO 4O 6O ~O aO eC tCa 2O aO 5O T:VK (SEC)

OIWL9 C. COOK NIT 2 (RJLL VS CORE}

fNNf 28b TlJRSINE TRIP EVENT 'WITHOUT l%ESSVRE CONTROL, NXINN REACTIVITY FEED8ACK

g2h i 1.

~ '0 I

I 560 5<0 c2h 500 0 10 20 30 40 50 60 70 dO QQ r ME (sEC) 700 580 560 6<0 620 600 8

580 580 540 520 IO. 20 30 40 50 60 '10 dO 90 I CQ rim (sac)

ONlLD C. COOK LNIT 2 (MIXED CORE) '

I6URK 29a TNSINE TRIP EVENT WITHOUT PRESSURE CNTROL, NXINN REACTIVITY FEEDSACK,

60 540 520 500

>0 20 30 40 50 60 70 60 yp T vK (SEC)

%%0 5150 5ip 620 500 8

5ao 560 5iO 520 0 >0 20 SO ip 50 50 70 .80 SC iCO T'MK (SKC)

NNALD C. CON UNIT 2 (FULL VS CNE)

FIQNE 29b TNBINE TRIP EVENT MlTHGUT-PRESSURE CNTROL, NXINN REACTIVITY FEEDBACK

QC g 1~00 90C.

n HPC 700.

500.

500 0, 10. 20. 30. 40. 50, 60. 10. bp. 90. 100.

~ TIME (SEC),

300 250 200 150 w 100 CC 50 0

n 50 0 10 20 30 40 50 60 70 80 90 100 T1& (SEC)

DONALD C. COOK UNIT 2 (MIXED CORE)

FI6URE 30a TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

300.

30C 700.

500.

500.

0. IO. 20. 30 <0 50 60 70 80. 90. IOC.

T ME (SKC) 400 350 300 250 200 l50 100 50 0

-50

]0 2Q 30 40 50 dQ 70 d0 90 1CO r uE (SEC)

Ot)NALO C. COOK UNIT 2 (FULL VS CORE)

FIGURE 30b TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NXII%N REACTIVITY FEEDBACK

25 20 15 10 ac ac

'4 5 ac 0

ac

-5

-10 "

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

DONALD C. COOK'NIT 2 (MIXED CORE}

FIGURE 3la TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, MAXIHLN REACTIVITY FEEDBACK .

25 20 V)

IO 5

0

-5

-10 0 10 20 30 <0 50 d0 70 So eo .CO TIME (SEC)

DONALD C. COOK UNIT 2 (FULL V5 CORE}

FIGURE 31b TURBINE TRIP. EVENT WITHOUT PRESSURE CONTROL, HAXIHN REACTIVITY FEEOBACK

q %s a rv 25CC 500 leer

"<cc

~

~,v vv ltIA eevbr 2 'QC 300.

i90C.

I t800

10. 20. 30. 40. 50 50 T'LIE (ggg) 2300.

1300.

1500.

<z 14QQ .

'V 1 200.

'A t QQQ.

0. 10. 20. 30. io. 50. dO. ZO. 50. 90. tQC.

TiMK (SKC)

ONAu) C. COOK UNIT 2 (lIIXH) CORE)

FIGVRE 32a TURBINE TRIP EVENT MITH PRESSVRE CONTROL, NXINN REACTIVITY FEEDBACK

~ ~

%A%

V I

50C t

.cQC C

n

~<hF a VV C

'900

'800 30. <0. 50. 60. 70. 50. 90 :GC 20.

T vK (SEC) 2".00

>30C. .~:tlj~i ~

>500

>400

>200 n

t 300.

0. 10, 20. 30. 40. 50. d0. 10. 50. 90. iOC r ~C '(SCC)

'ONlD C. COOK UNIT 2 (FULL V5 CQRE)

FI6NE 321 TURBINE TRIP EVENT MITH PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

dt 4

Z 0.

10 20 30 <0 50 50 70 80 9C r vK (SKC) 2.6 3 ~.z

~ 2 0 10 20 30 40 50 50 70 d0 90 Tlat@ (SEC)

OOQLG C. COOK NIT 2 (MIXED CORE)

FI6NE 33a TURBINE TRIP .EVENT MITH PRESQNE CONTROL, NXINN REACTIVITY FEEOSACK

l0 20 30 40 50 50 10 80 90

~ vK (SKC) lO 20 30 40 50 dO 10 60 9C T ~K (SKC)

ONIALO C. COOK UNIT 2 (FULL VS CORE)

FISuaz 33b TlJRSINE TRIP EVBIT MITH PRESSURE CONTROL, NXINN REACTIVITY FEEDSACK

5~0 620 I

I r vS Car

<<V 560 5<0 520 500 0 !0 20 30 40 50 60 l0 80 9C r ~E'SEc) 700 580 560 640 520 500 8

580 560 g

5L0 520 0 l0 20 30 40 50 60 10 80 90 lC" TivK (SKC) 00NLD C. COOK UNIT 2 (NIXEQ CORE}

FI6URE 348 TURBINE TRIP EVENT KITH PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

550 t 54C e 520 500 '0 0 20 30 <0 50 60 70 80 T vK (SKC',

0 I

I I

530 5~0 620 50C 2

580 3 560 5c0 520 500 io 20 30 io 50 60 ~0 ao ec :CO T ilK (SEC)

ONALD C. COOK UNIT 2 (FULL V5 CORE)

FIeNE 34b TURSINE TRIP EVENT 'KITH PRESSURE CONTROL, NXINN REACTIVITY FEE08aCV.

c

?J7 .-QC.

z 30C.

BCC.

D 700.

500.

500.

p. 10 '0 '0. 40.

T MK

50. 60.

(SEC)

70. 80. 9p. 1pc 300 250 200 150 OC 10Q CZ 50 0

n

-50 '60 10 20 30 40 50 70 SO 90 1CP Tlute (SEC)

DONALD C. COOK UNIT 2 (HIXED CORE)

FIGURE 35a TURBINE TRIP EVENT WITH PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

P'00 9CC 600.

500.

10. 20. 30 '0.

T:ME

50. 60.

(SEC)

70. 80. 9p. Ipp 400 350 300 250 200 150 100 50 0

-50 10 20 30 40 50 60 70 80 90 ICO TIME (SEC)

DONALD C. COOK UNIT 2 (FULL V5 CORE)

FIGURE 35b TURBINE TRIP EVENT WITH PRESSURE CONTROL, AXING REACTIVITY FEEDBACK

25 20

'A )5

)0 QC ac 5

5 0

-5

)Q 20 30 40 50 50 70 80 90 )GO T)MK (SKC)

PONALD C. COOK UNIT 2 (HIXEO CORE)

- FIGURE 361 TURBINE TRIP FVENT MITH PRESSURE CONTROL, NX'INN REACTIVITY FEEOBACK

25 20 10 ac ac 5

0

-5

-10 0 t0 20 30 40 TIME 50 50 (SEC)

'0 80 90 ICO DONALD C. COOK UNIT 2 (FULL V5 CORE)

FIGURE 36b TURBINE TRIP EVENT MITH PRESSURE CONTROL, MAX!NN REACTIVITY FEEDBACK

5CC "5CC 1

n 2 ICC I

C

".QG.

900.

I800.

0. tp. 20. 30. iP. 50. 60. 70. 50. yp T uK (SKC) 300 t300.

'6QC ac

'<OC C

v

>200 n

n I QOC.

0. l0. 20. 30. 40. 50. 60. 70. 80, 90. IOO.

T5VK (SE'C)

DONALD C. COOK UNIT 2 (IIIXED CORE)

FIGURE 37a TURBINE TRIP EVENT QITH PRESSURE CONTROL, MINN@ REACTIVITY FEEOBACK

5QC n

w gAQ e v C

~

'n 2 ~00 V) 1600 40. 50. 50. 10. 80. 90.:OC.

) 0. 20. 30.

T: VK (SEC) 2'300 .

1800.

1600.

I 400.

"4 l200.

1000.

600.

0. ~0. 20. 30. i0. 50. 60. 10. d0. 90. ~OC.

7 ~ & (SEC)

OONLO C. COOK NIT 2 (FULL VS CORE)

FIQIRE 37b TURBINE TRIP EVENT 'MITH PRESSURE CONTROL, NINNN REACTIVITY FEE08ACK

10 20 50 <0 50 60 7Q 60 gC r vK (SgC) 2 8 6

"2 1 6 4 ~Q 20 30 40 '0 T1QK 64 (SEC) 70 60 g)

OONU) C. COOK UNIT 2 (llIXEO CORE) fI6NE 38'URSINE TRIP EVENT MITH PRESSURE CONTROL, NINNPl REACTIVITY FEEDBACK

Z

0. ic 40 50 10 20 30 d0 d0 90 T MK (SEC}

4 5 3 5 2.5 I.S

l. 0 30 . io 50 10 70 10 20 80 SO tCO Ti& (SEC)

OQNLD C; COOK UNIT 2 (FULL VS CORE)

FIQNE 38b TRIP EVENT NITH

'URSIHE PRESSURE CONTROL SINN@ REACTIVITY FEEDBACK

560 t

520 500 0 10 20 30 40 50 60 70 80 9C '"0 I MK (SEC) 680 560 5~0

~ 520 500 550 560 540 520 500 "

0 10 20 30 40 50 60 10 80 90 '00 TivK (SEC) 00NALD C. COOK UN?T 2 (NIXED CORE)

F lGURE 39a TURSlNE TRlP EVENT 'MlTH PRESSURE CONTROL, NlHUNN REACTLVITY FEEOBACK

4, I

I cog iI I

520 500 0 >0 20 30 <0 50 60 70 T vK (SEC) 30 I

68G 660 5<0

r. 2r.

630 580 560 3

5i0 520 500 'l0 20 30 40 50 60 70 80 90 iCQ TivK (SKC)

NXQLO'C. COOK UNIT 2 (FULL V5 CORE)

FIGURE 3Sb TURBINE TRIP EVENT QITH PRESSURE CONTROL, NINNN REACTIVITY FEEDBACK

n 13QC.

700.

500.

500.

10. 20. 30. 40. 50. 60. 70. 80. 9Q.  !QC.

T ME (SEC) 40Q s) 350 300 "50 200 150 100 50 0

50

0. 10 20 30 40 50 60 70 80 90 >00 TiMK (SEC)

DONALD C. COOK UNIT 2 (MIXED CORE)

FIGURE 40a TURBINE TRIP EVENT QITH PRESSURE CONTROL, MINIMUM REACTIVITY FEEDBACK

'00.

el 3PG.

MV 7PG.

500.

500 0 ~ 10 ' 20 30 '0'0 '0'0 T ME (SEC)

~ 80. 90. 'CC.

500 n

400 1 I

(

3OO <

I 200 i 100 J) 0 n

-100 0 10 20 30 40 50 60 70 do 90 iCO TlMK (SEC)

OONALO C. COOK UNIT 2 (FULL VS CORE)

FIGURE 40b.

TURBINE. TRIP EVENT WITH PRESSURE CONTROL, HININN REACTIYITY FEEOBACK

40 35 30 25 20 15 gA

'4 ]Q 5

-5

-10 0 10 20 30 40 50 60 lO 80 90 'C3 T'ME (SEC)

DONALD C. COOK UNIT 2 (MIXED CORE)

FIGURE 41 a TURBINE TRIP EVENT MITH PRESSURE CONTROL, HINIMN REACTIVITV FEEDBACK

30 41 2c 20 15 1Q Ag J7 0

-1Q 0 10 20 30 40 50 60 70 80 90 TIME (SEC)

DONALD C. COOK UNIT 2 (FULL V5 CORE)

FIGURE 41b TURBINE TRIP EVENT MITM PRESSURE CONTROL, MINIHUH REACTIVITY FEEOBACK

APPENDIX A SIGNIFICANT HAZARDS EVALUATION

>A SIGNIFICANT HAZARDS EVALUATION DONALD C. COOK UNITS 1 & 2 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 ifoperation of the facility in accordance with the proposed amendment would not: 1) involve a significant increase in the probability or consequences of an accident previously evaluated, or 2) create the possibility of a new or different kind of accident from any accident previously evaluated, or 3) involve a significant reduction in a margin of safety.

DESCRIPTION Of AMENDMENTRE VEST:

The purpose of this amendment request is to revise Technical Specification Section 3/4.7 for both Donald C. Cook units in order to relax the main steam safety valve (MSSV) lift setpoint tolerance from <1%

to J3%. The currently specified tolerance of J1% of the liftsetpoint can be difficultto meet when the valves are tested due to setpoint drift over the duration of the operating cycle. This evaluation will provide margin for American Electric Power Service Corporation (AEPSC) when they perform their surveillance testing.

The ASME Code requires that the valves liftwithin 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.

A-1

BASIS FOR NO SI NIFICANT HAZAIU)S DETERMINATION:

The effects of increasing the as-found lift setpoint tolerance on the main steam safety valve have been examined for the non-LOCA accidents, 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.

The effect of an increase in the allowable Main Steam Safety Valve set pressure tolerance from +1% to

+3% on the UFSAR LOCA analyses has been evaluated. In each case the applicable regulatory or design limitwas 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 remained below the 10CFR50.46 2200'F limit.

The steam generator tube rupture event was also analyzed to determine the effects of the lift setpoint tolerance increase. The results of the analysis concluded that there was a very slight increase in the whole body dose release for Unit 1, but the magnitude of the increase was SECL-91%29, Revision 1 within the uncertainty associated with the calculation itself, and that the releases generated for the Donald C. Cook Rerating Program bound those calculated for this evaluation. The evaluation also determined that the current Unit 2 doses remain bounding. Thus, the conclusions presented in the Donald C. Cook UFSAR remain valid.

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 liftsetpoint tolerances willhave no impact on the containment integrity analysis. In addition, based on the conclusion of the transient analyses, the change to the MSSV tolerance will not affect the calculated steamline break mass and energy releases inside containment.

A-2

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 J3% 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 not already discussed in the UFSAR. 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. For the events analyzed, all applicable acceptance criteria were satisfied, and there was no increase in the doses over those previously generated. As a result, the conclusions presented in the Donald C. Cook UFSAR are unaffected by the proposed change. 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. No accident willbe created that will increase the challenge to the MSSVs or result in increased actuation of the valves. Therefore, the possibility of an accident different than previously evaluated is not created.

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 reduced by the change in the MSSV lift setpoint tolerance. The proposed Increase in the as-found MSSV lift P

A-3

setpoint tolerance will not Invalidate the LOCA or non-LOCA conclusions presented in the UFSAR accident analyses. The new loss of load/turbine trip analysis concluded that all applicable acceptance criteria are still satisfied. For all the UFSAR non-LOCA transients, the DNB design basis, primary and secondary pressure limits, and dose limits continue to be met. Peak cladding temperatures remain below the limits specified in 10CFR50.46. The calculated doses resulting from a steam generator tube rupture event remain within a small fraction of the 10CFR100 permissible releases.

Thus, there is no reduction in the margin to safety. Note, however, in order to implement the proposed change, the Technical Specifications will have to be changed.

3.7.1.1 All aain stoma line coda safety valvea aasocLaeed vieh each sees.

generator shall bo OPEkASLE.

I IIC4HLBX:

thCGM:

ao VLeh 4 reactor coolant loopa and aaaociatad seaaa generacot..s Ln operation'assd vieh ona or aora aain ateaa lima code sefecy valvoa Lnoyorabla, operation Ln NOES 1, R and 3 aay proceed yrovidad, that within 4 houra, either eho Lnoparabla valve Ls raatorad to OPXMLI atatua or eha hwer 4nge Neutron fLux High Satpoint triy ia reduced yor Table 3.1-1.; othe~a, io Ln at laaat NT STARlT viehin eha naxt C houra and Ln Cog SMVTKNN vithin eho following 30 boura. >t e

b. VLeh 3 raactor coolant looya an4 aaaociatad staaa gaaeraeogs Ln oyoratioss an4 vieh one or mra aain ataaa lina code safeey valvea aaaociatad vieh an operatic loop Lnoporabla, operaeLon Ln NRC 3 aalu proceed providad, that &thin 4 houri, either the Lnoporablo valve La raatorad to OHRALLC aeatua or che reactor trip breakers are opane4; othariiao, bo in COLO SRUTEOQN vtthin eha next 30 bours.

C~ The proviaiona of Spocificatioo 3.0.4 are not apylicable.

4.7.1.1 Each aain a~ liao code aafaey valve ahaG bo 4eeonaeraeed OPEMlJ, rich life aottiags and orifice aixaa aa ebs Ln Table 4,7 1, Ln accordance etch, Soetioss ZI of eho AQC loilar and Praaaura Vaaaal Coda, 1914 gee.

D. C. COCC ~ URXZ 1 3/4 7-1 agama NO.ig0

TABLE 3.7-l HNIINN ALLONkE ONER RAHGK lKUTRON fLUN HIGH SETPOINT MITU INOPERhBLE STEAN lEFWlKflll

~ e

~

C Hexf~ Al)owable Power Range Naxtam Naker of feeyorable Safety Neutron flux High Setpoint Valves oa la ati Steaa Caaarator Percent of RATKD TERNAL PSKR 13.6

n 5%

oo Nl $ 0CS yeiy 1C in.

h N1 'I

$ 045 I

peiy LC in oo N-3 5075 peig 1C ln I

4e NR $ 07I yeiy W

1C in.

~o N3 k$ peiy 1C in.

I A

+fho l tt catt praaaaro aball oorroayqn4 aoaiaal oporatiay taeperatura ae1 proeeur' to aabieat aedltlone ot the yalya at.

Tho OPERAITLI.Y of eha aain seoaa line coda safoey valvoo anagram Iocondaty Iyo coo proasuro vil1 bo Liiieo4 eo vi chin i ea do s '.gn pzoaguro of 10f5 paid durinj the oooe sovoro aneicipaeod syseoN opera.

eional eranaionc. The aux~'oliovini capaeiey i4 aaoociaeid vi h I eutbino erip froa 100% RATS THERMAL t5CL coincident vieh an aaavuaod .':

of eondonsot hoac sinJa (i.o.. no seaaa byyaaa eo eho condonaot).

The Ipooifiod valve life coceinla an@ rolioving capaeieioo are in aocozdaneo viA eho zoquiroaenea of 5occion ZTZ of eho QlC Soklor and prooquto Code L97L Cdi cion. The cecal rolioving cayao icy for al L valvo on a o g coaa noo o L7 L53 . lOO Lba/ht vhieh ia apyroaiaaco ly LR

~

pot'cone of cho eoeal secondary acorn Gee of LL.L20,000 LboAg ae atagg. tOQXR. A aint'f 2 OPCRAILC aafoey valvoo per oporabl ~

gcaaa gonotaeor onouroo ehac ouffioione rolieCag capacity ia evai

[00'ATZy lo for eho allowable ZHQ8AL PNC toactiot&a Ln Table 3.7 ~ L.

STARTUt and/or tQCL OPERATION ii allerahlo vieh aafocy val inoyorablo +%chan cho Liiicaciona of the iCZZM r~iroaoncs on eho bao'.

of eho reduction. in secondary oyseee ae~ fZov aad TRLLCQ. tOMER zoq .

by eho rodueod reactor etiy ooccinga ~ f cho lover Range Noueron Flax channela. The reactor erfy aocyoint ro4aciona are darivo4 on eho foLLoving baooo:

For 4 Looy oporaeion a (L0%)

%hero:

5P ~ N4acod toaccot eriy ooeyoint ia potcone of RATtD THELVL 8%lLL V ~ eaaSaa nuabet ot inoyotailo aafocy valvoo por scoaa 1ino L.,2 or 3.

X ~ Toeal rolkoving cayaaity ot all oafoey valve! por aeoca Line ~ 4.off,454 Lbo/beut.

Y ~ Nacilua roliovinl eayacicy ot any one cato'ey valve

~ f57,C94 Lbo/hour, (109) ~ Rover Rancho Neutron Ficta-High Ttiy Soepoine fot 4 loop oyoracion.

O..C. CXC ~ UNION 1 ) 3/i $ L AN~tKNT NO.

3,7,1.1 hL1 matn%Egal seaaa leone coda sa.aey valves assoc'.acid viA each stean jenaraeor sha11 be OPELQQ v'. 5 Life seer'gs as speci'f ed '.n TabLe 3: I -'a.

2 i ~

ao Vkeh 4 reactor coolane Loops and associated seeaa generaeo s Ln cyerae'on and vieh one or mora Iakn seeaa LW coda.sa eey valves

~ rable, eparaeton La CNS 1, 2 and S may proceed yrovided, chat vtdgn 4 bees, etcher ehe inoperable valve ts reseored eo vichin eho neat C ~s ~~

OPQhlLX jeacQ$ Qr ehe ?4%%r iange ÃoLeron F11% Ekgh Trip Sec[oint.

ia reduced year Table S.l-l: otherwise, be in at Lease Bet ca@ La COTE 51CTtRKNN vtehfa ehe follm4ag 30 heats. i

b. VSch 3 reaotor coolant looya aaL associated steam generators bi operation aa4 etch one or sere aaSa steam Lhse code sa"oey valves aaaoetato4 &th an ~racial 3eoy taeporable, eyeraef.on ta MDL 3 may yrocoo4 ytevtdad, chat vtthta l beati, eiehet the i.noyerable valve Sa reaeored te OZQQLX status er ehe reactor trLy brewers are eyeaed; etheaCae, be Qx COLO SRUTI% withe ehe next 30 hexa.

'The yxevta5.oaa of SpoctNcaeton 3.0.I are not ayylfcable, 4.?.L.L Io e44LCLeaai SerretlLcaee teqCr~ta eehez than chose ~red by 4.t.$ .

S/a 7~1 AjgÃKICRT 50. 82

TABLE 3. l-l INXINll ALL@NB.K PSKR RANGE NK~U~F SETPOIIIT lIITII INOPERABLE STEAH Nax)mm h))mab)e Poser Range Saxi~ Nuwber of le Safety NeNtroa Flux lllgh Setpoiat Va ves oa or Cerement of RATEO TIIENHL PONER 87.2

ZAlkf 3.7-h STEIN Ltd SQ'HY VALVfS ffN lOOP 81+

VM llfT SEHl ORIFlCE SIZE

a. SV-l l065 psig l6 i li. SV-l )065 psig 16 in.~

c. SV-2 l075 psig )6 in.~

1. SV-2, l075 prig l6 in.2

e. SV-3 )NS ysiS l6 in.~

l% mme XI'ressure slull cerrespoal to oehieat coa4itioas of Qe valve at eewiaal oyeratiay teayerebee.aal yra5ssre.

Tho OHRQIUTT of cho cata sceaa ltno eo4a aafecy ~aires eaaeea

~c ee seceataxy Iystaa )casanova <11 Q ltatca4 ce WN,a ll0o of tcs oazbtne 104i of aen4ensor beaC sink (L,e., M

~

4ast~ yciseure of 104$ Pstg 4ctag Cho aesC severs anctctpace4 eyscaa oPoractana1 transient. The aaxtaa ralteCag ceyaaicy ts assoctaca4 vSch a crt'~ TRENT 8$ ZR aotnatdanc rich an ass~4 1ois s~ l+ass ce che aon4ansaz).

Tbe syoetfto4 Mw 1SA sottSILgs an4 reltovtag ecyacittas are tn aeeor4anae etch cho reqatr~cs of Soertoa III of cho &tier

~gggg~p Pros~e v res Co4e, 1071 Mic oe s~ Tbe cecal linea toit~ A58R ecyactcy of lT,U$ ,000 lhsiht ~ah ta a11 an4 aafocy 100'ATZO ~g, oa e La ac lease 10f

~tcanc of 84%~ soaon~ sc440 AM race 5ggR. i Ntsga% of ! OMAlLS aafecy M&s Por s~ gonatacar che ae chas eatttatane reit~ aayaetry ta ~ladle fer Ihe alletahlo tRQNAL toglkgos

?OCR toscrta!Soi ta Taile 3.7 l.

STIRXQP tseyerailo withe ea4/ot 8$ CL OPmliTKON te allowable etch safely che 1$ akcactoes ot the AC?TM ~reeencs oa the

~

hasta of che re4sacioo ta soaea4axy aye~ s~ flee sni Thtlsg. 8ÃCR-chIRhllso fellatio bases:

The reeccer ~ ee~tkc r~atxe4 iy Che te4aae4 reaecer.eriy eeeeSNge ef Ae Peat f04Nrtooe are 4ert~

Range'1~

eO che ga l 1eey eyeracQe a (i')

Aero:

St a re~ reeecee TIRlh 8%&

arty eeeyeLae La Poreene of lCCl 1a aml~ aeAer ef Saeyetahle safeey Weel Per seem

@as Y=-

'~ Ieiil relS~ eoyoetry SB Qe. /bees e 4,Q!,4S of all safoey valves Per stable

~~.Pe+'aSt, Sa O~

rolteviag eayac&y ef See

~ one safoey va1ve 10' teat Osage

~ ye ra@tee See~ Plm ~ ltd Seeyets! fer 1 leep

~ WCLCaa tLaa mt a 1 $ /4 liL sammy Io. $ 2.

INNT A he safety nl>e )s OPERABLE ~)th a 1 )ft setting of'W value. H~r, about the safety valve shall be reset to the noa)nalthe nmfnal whenever f~ outs1de the +1% tolerance. value +]%