ML17329A673

Rev 1 to SECL-91-429, Main Steam Safety Valve Lift Setpoint Tolerance Relaxation.

ML17329A673
Person / Time
Site:	Cook
Issue date:	11/11/1992
From:	WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:
Shared Package
ML17329A671	List: ML17329A670 ML17329A672 ML17329A673
References
SECL-91-429, SECL-91-429-R01, SECL-91-429-R1, NUDOCS 9211170225
Download: ML17329A673 (215)

Text

ATTACHMENT 4 to AEP:NRC:1169 WESTINGHOUSE REPORT SECL-91-429, Revision 1, "DONALD C. COOK UNITS 1 AND 2 MAIN STEAM SAFETY VALVE LIFT SETPOINT TOLERANCE RELAXATION" 92iii70225 92iiii PDR ADOCK 050003i5 P PDR

SECL-91-429, Revision 1 DONALD C. COOK UNITS 1 R 2 HAIN STEAN SAFETY VALVE LIFT SETPOINT TOLERANCE RELAXATION Nuclear and Advanced Technology Division Westinghouse Electric Corporation September 1992 1992 Westinghouse Electric Corporation All Rights Reserved

SECL-91-429, Revision 1 LIST OF CONTRIBUTORS Jeffrey C. Bass Leigh A. Brooks Robert W. Garison Scott R. Griffith Greg J. Hill Robert G. Orendi William J. Rinkacs Tim D. Rowell Ken Rubin Jill L. Stackhouse Hike B. Watson Haureen R. Zawalick

SECL-91-429, Revision 1 TABLE OF CONTENTS SECTION PAGE List of Tables List of Figures Safety Evaluation Check List vii Introduction Licensing Basis Evaluations Non-LOCA 5 LOCA 20 Containment Integrity 24 Steam Generator Tube Rupture .25 Component Performance 27 Systems Evaluation 27 Radiological Evaluation 27, Plant Risk Analysis (IPE) 27 Plant Risk Analysis (non-IPE) 28 I&C Systems 28 Technical Specifications 29 Assessment of No Unreviewed Safety guestion 29 Conclusion 33 References Appendix A: Significant Hazards Evaluation Appendix B: Recommended Technical Specification Marked-Ups

SECL-91-429, Revision 1 LIST OF TABLES TABLE PAGE Table 1: Main Steam Safety Valve Lift Setpoints Table 2: DNB Design Basis Transients Not Affected Affected by MSSV Lift Setpoint Tolerance Increase Table 3: Unit 1 Turbine Trip Sequence of Events 35 Table 4: Unit 2 Turbine Trip Sequence of Events 37 Table 5: Current Licensing Basis Steam Line 39 Safety Valves per Loop Table 6: MSSV Setpoint Increase Steam Line 4O Safety Valves per Loop Table 7: Unit 1 Low Pressure Low Temperature 41 Input Parameters Table 8: Unit 1 Low Pressure High Temperature Input Parameters Table 9: Unit 2 Low Pressure High Temperature Input Parameters Table 10: Unit 1 Small Break LOCA Evaluation 44 Time Sequence of Events Table ll: Unit 1 Small Break LOCA Evaluation 45 Summary of Results Table 12: Unit 2 Small Break LOCA Evaluation 46 Time Sequence of Events Table 13: Unit 2 Small Break LOCA Evaluation 47 Summary of Results

SECL-91-429, Revision 1 LIST OF FIGURES FIGURE Figure la: Illustration of Overtemperature and Overpower hT Protection for Unit 1 Figure 1b-c: Illustration of Overtemperature and Overpower AT Protection for Unit 2 (mixed and full V-5H 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 HSSV 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: Unit 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, Haximum Reactivity Feedback: Steam Generator Pressure and HSSV Relief Rate 111

0 SECL-91-429, Revision 1 LIST OF FIGURES (Continued)

FIGURE Unit 1 Turbine Trip Event Without Pressure Control, Maximum Reactivity Feedback:

Pressurizer Relief Rate Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback:

Pressurizer Pressure and Water Volume Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback:

Nuclear Power and DNBR Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Core Average Temperature and Loop Temperature Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback: Steam Generator Pressure and HSSV Relief Rate Unit 1 Turbine Trip Event With Pressure Control, Maximum Reactivity Feedback:

Pressurizer Relief Rate Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback:

Pressurizer Pressure and Water Volume Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback:

Nuclear Power and DNBR Unit 1 Turbine Trip Event With Pressure Control, Hinimum Reactivity Feedback: Core Average Temperature and Loop Temperature Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback: Steam Generator Pressure and HSSV Relief Rate Unit 1 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback:

Pressurizer Relief Rate

SECL-91-429, Revision I LIST OF FIGURES (Continued)

FIGURE Figure 22a-b: Unit 2 Turbine Trip Event Without Pressure Control, Hinimum Reactivity Feedback:

Pressurizer Pressure and Water Volume Figure 23a-b: Unit 2 Turbine Trip Event Without Pressure Control, Hinimum Reactivity Feedback:

Nuclear Power and DNBR Figure 24a-b: Unit 2 Turbine Trip Event Without Pressure Control, Hinimum Reactivity Feedback: Core Average Temperature and Loop Temperature Figure 25a-b: Unit 2 Turbine Trip Event Without Pressure Control, Hinimum Reactivity Feedback: Steam Generator Pressure and HSSV Relief Rate Figure 26a-b: Unit 2 Turbine Trip Event Without Pressure Control, Hinimum Reactivity Feedback:

Pressurizer Relief Rate Figure 27a-b: Unit 2 Turbine Trip Event Without Pressure Control, Haximum Reactivity Feedback:

Pressurizer Pressure and Mater Volume Figure 28a-b: Unit 2 Turbine Trip Event Without Pressure Control, Haximum Reactivity Feedback:

Nuclear Power and DNBR 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, Haximum Reactivity Feedback: Steam Generator Pressure and HSSV Relief Rate Figure 3la-b: Unit 2 Turbine Trip Event Mithout Pressure Control, Haximum Reactivity Feedback:

Pressurizer Relief Rate Figure 32a-b: Unit 2 Turbine Trip Event Mith Pressure Control, Haximum Reactivity Feedback:

Pressurizer Pressure and Water Volume

SECL-91-429, Revision 1 LIST OF FIGURES (Continued)

FIGURE Figure 33a-b: Unit 1 Turbine Trip Event With Pressure Control, Haximum 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 HSSV Relief Rate Figure 41a-b: Unit 2 Turbine Trip Event With Pressure Control, Minimum Reactivity Feedback:

Pressurizer Relief Rate

SECL-91-429, Revision 1 Customer Reference No(s).

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

WESTINGHOUSE NUCLEAR SAFETY SAFETY EVALUATION CHECK LIST

1) NUCLEAR PLANT(S): OONALD C. COOK UNITS 1 AND 2

2) SUBJECT (TITLE) 'ELAXATION OF HSSV SETPOINT TOLERANCE TO + -3%

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

Parts A and 8 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 Hay 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 Nay 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?

vi 1

SECL-91-429, Revision 1 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 8 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 IOCFR50.59(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:

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

Reason for/Description of Change:

UFSAR Mark-u s to be rovided b se grate transmittal

6) SAFETY EVALUATION APPROVAL LADDER:

6. I) Prepared by (Nuclear Safety): Date:

6.2) Reviewed by (Nuclear Safety): Date: 9/d 2.

6.3) Nuclear Safety Group Manager: Date: 0 l

SECL-91-429, Revision 1 DONALD C. COOK UNITS 1 & 2 INCREASED HAIN STEAM SAFETY VALVE SETPOINT TOLERANCE SAFETY EVALUATION I. INTRODUCTION American Electric Power Service Corporation (AEPSC) has found that over an operating cycle the setpoint of the Hain Steam Safety Valves (HSSVs) 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 HSSVs at Donald C. Cook Units 1 & 2. The following safety evaluation is provided to support changing the as-found lift setpoint tolerance as stated by the Technical Specifications from +1%

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 +1% to account for future accumulation of drift.

Thus, this evaluation permits a +3% setpoint tolerance to address as-found conditions.

The HSSVs 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).

SECL-91-429, Revision 1 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).

The operation of the Class 2 main steam safety valves (HSSVs) is governed by the ASHE Code (Reference 2). AEPSC will maintain the design basis of the HSSVs by ensuring that the valves, if outside the +lX tolerance, will be recalibrated to within +1X. The purpose of this evaluation is to provide a quantification of the effects of a higher as-found lift setpoint tolerance. This safety evaluation will address the effects of the +3N 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 lift setpoint tolerance.

0 SECL-91-429, Revision 1 TABLE 1 MAIN STEAM SAFETY VALVE LIFT SETPOINT VALVE NUMBER LIFT SETPOINT (+I/o)

SV-1 1065 psig (1080 psia)

SV-1 1065 psig (1080 psi a)

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

SECL-91-429, Revision I II. LICENSING BASIS Title 10 of the Code of Federal Regulations, Section 50.59 (10 CFR 50.59) allows the holder of a license authorizing operation of a nuclear power facility the capacity to initiate certain changes, tests and experiments not described in the 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 lift setpoint 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) (I) 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 lift setpoint 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.

SECL-91-429, Revision 1 III. EVALUATIONS The results of the various evaluations from the Nuclear Safety related disciplines within Westinghouse scope are discussed in the following sections.

l. Non-LOCA Evaluation The non-LOCA accident analyses that are currently presented in the UFSAR modelled the MSSYs as a bank of five valves, all of which having a lift I 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).

+3% Tolerance:

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

AT Protection The increase in the MSSV lift setpoint tolerance has the potential to impact the Overtemperature hT and Overpower hT setpoint equations. Referring to Figure la for Unit 1 and Figures lb and lc (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.

SECL-91-429, Revision I If the current OTAT setpoint coefficients (KI through K3) result in protection lines that just bound the thermal core limits, it is possible that by lowering the SG safety valve line to the right, a portion of the core limits will be uncovered.

In order to evaluate the effects of the increase in the setpoint tolerance, the Overtemperature AT and Overpower bT setpoint equations (Kl through K6) were examined to determine if the equations remained valid assuming that all 20 NSSVs 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 1owering 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, Ib, and lc.

DNB Events 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 HSSVs, 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 non-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

SECL-91-429, Revision 1 TABLE 2 DNB DESIGN BASIS TRANSIENTS NOT AFFECTED BY MSSV LIFT SETPOINT TOLERANCE INCREASE EVENT 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 Break - Core Response) 14.2.5 Loss of Reactor Coolant Flow (Includes Locked Rotor Analysis) 14.1.6 Uncontrolled RCCA Bank Withdrawal From a Subcritical Condition 14.1.1 Uncontrolled RCCA Bank Withdrawal at Power 14.1.2 RCCA Misalignment 14.1.3

SECL-91-429, Revision 1 the analysis of this event, and thus, changes to the HSSVs have no impact on this event. Therefore, the results and conclusions presented in the UFSAR remain valid.

Steamline Break Mass 5 Ener Releases For the steamline break mass and energy releases, the steam release calculations are insensitive to the changes in the HSSV lift setpoints since the vast majority of these calculations result in depressurizations of the secondary side such that the HSSVs are not actuated. For the smaller break cases that might result in a heatup, one HSSV 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 Section Steamline Rupture Mass 5 Energy Releases WCAP-11902 Inside Containment Supplement 1 Steamline Rupture Mass 8 Energy Releases WCAP-10961 Rev 1 Outside Containment for (current)

Equipment Environmental gualification Submittal AEP:NRC: 1140*

(approved 11/20/91)

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

(included in WCAP-11902, Supplement 1)

SECL-91-429, Revision 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 UFSAR Section Loss of All AC Power to the Plant Auxiliaries (Loss of Offsite Power LOOP) 14.1.12 Loss of Normal Feedwater (LONF) 14.1.9 Feedwater System Pipe Break (FLB)* 14.2.8

• 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 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

SECL-91-429, Revision 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 psi'a. Since the evaluation, in which a +3% HSSV 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 HSSVs as well as a +3M 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 NSSV lift setpoint tolerance of +3M 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. 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.

SECL-91-429, Revision 1 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 HSSV setpoint tolerance from -1N to -3X. 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 llN 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 lift setpoint tolerance (-3X) does not result in the HSSVs remaining open at a saturation temperature outside of the range identified above, the existing mass releases remain valid (Reference 9).

SECL-91-429, Revision 1 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 HSSV 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 represents the lowest steam pressure considered in the mass calculations. Thus, the existing releases include a reseat pressure approximately 5.5N 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 Summar Thus, based on the discussions presented above, only one UFSAR non-LOCA transient is impacted such that a new analysis must be performed in order to address the effects of the NSSV lift setpoint tolerance increase from +1% to

+3K. 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 8 2 UFSAR remain valid.

SECL-91-429, Revision I Non-LOCA Anal sis:

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 AT, high pressurizer pressure, or low-low steam generator water level.

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

SECL-91-429, Revision 1 common lift setpoint. By modelling the staggered behavior of the HSSVs, 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 2X 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.

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.

SECL-91-429, Revision 1

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

f. Only the overtemperature hT, 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 HSSV was modelled to ramp linearly from no flow at its lift setpoint (3X above the nominal Technical Specification setpoint) to full open flow at its full open point (6X 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 ASHE 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 pr'imary pressure for pressure cases.

Results 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.

SECL-91-429, Revision 1 UNIT 1 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 llON of the design value.

Case B:

Figures 7 through 11 show the transient response for the turbine trip event under maximum 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 th'e 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 110X 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

SECL-91-429, Revision 1 UNIT 1 continued 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 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 sis Conclusion Unit 1 Based on the results of these Unit 1 turbine trip analyses with a +3%

tolerance on the HSSV 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.

SECL-91-429, Revision 1 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 llOX of the design value. The main steam safety valves are also actuated and maintain secondary pressure below llOX of the design value.

Case 8:

Figures 27a through 3lb 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 110X of the design value. The main steam safety valves are also actuated and maintain secondary pressure below 110X 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

SECL-91-429, Revision 1 UNIT 2: continued 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 110X of the design value. The main steam safety valves are also actuated and maintain secondary pressure below 110X of the design value.

Case D:

Figures 37a through 41b show the transient response fo} 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 110X of the design value. The main steam safety valves are also actuated and maintain secondary pressure below 110X of the design value.

Anal sis Conclusion Unit 2 Based on the results of these Unit 2 mixed and full core turbine trip analyses with a +3X tolerance on the NSSV 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 llOX of design at all times.

SECL-91-429, Revision 1 Non-LOCA Conclusions 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 still 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. LOCA and LOCA Related Evaluations Lar e Break LOCA The current large break LOCA analyses for Donald C. Cook Units I and 2 were performed with the NRC approved 1981 Evaluation Hodel 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 HSSVs 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 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 HSSV setpoint in the large break evaluation model. Therefore, an increase in the allowable HSSV setpoint tolerance for Donald C. Cook Units I and 2 will not impact the current UFSAR large break LOCA analyses.

SECL-91-429, Revision I Small Break LOCA The small break LOCA analyses for Donald C. Cook Units I and 2 were performed with the NRC approved Evaluation Model using the NOTRUMP code. After a postulated small break LOCA occurs,'he 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 I 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 I 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 I. 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 I 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.

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 +30X to +13X for the MSSV increase analysis. An axial offset of +13N is equal to the value assumed in the licensing basis large break LOCA

SECL-91-429, Revision 1 analysis. In addition, the licensing basis analysis conservatively assumed a maximum assembly average power (P>A) of 1.519. The 3% increased HSSV setpoint tolerance analysis assumed a PMA which was reduced to 1.46. In order to obtain a direct sensitivity for the increased HSSV setpoint tolerance, a NOTRUHP analysis was performed incorporating these assumptions but modelling the original HSSV setpoints.

Tables 5 and 6 summarize the HSSV 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 HWt and the low pressure, low temperature operating conditions. This value is less than the acceptance criteri a limit of 2200'F. The maximum local metal-water reaction is 3.47%, 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 1N criterion of 10 CFR 50.46.

The time sequence of events and results of the Unit 2 analysis are summarized in Tables 12 and 13, respectively. The 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 HSSV 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 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.

SECL-91-429, Revision I Post-LOCA Lon Term Core Coolin The Westinghouse licensing position for satisfying the requirements of 10 CFR 50.46 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 HSSV actuation. Thus the post-LOCA long-term core cooling evaluation is independent of the HSSV setpoint tolerance, and there will be no change in the calculated RCS/sump boron concentration after a postulated LOCA for Donald C. Cook Units I and 2.

Hot Le Switchove~ 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 inthe core. This time is dependent on power level and the RCS, RWST, and accumulator water volumes and with their associated boron concentrations. The proposed HSSV setpoint tolerance increase to 3X 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 HSSV setpoint tolerance increase to 3N does 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

SECL-91-429, Revision 1 tolerance increased to 3%, Unit 2 LOCA analyses assumed a reduced core power, 3250 NWt, 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 boil-off rate 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 Forcin 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 NSSV may actuate, the increase in the NSSV setpoint tolerance to 3% will not impact the LOCA hydraulic forcing functions calculation for Donald C.'Cook Units 1 and 2.

LOCA Conclusions The effect of increasing the NSSV setpoint tolerance to 3% for Donald C.

Cook Units I 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 NWt when the high head cross tie valves are closed, it was shown that the 3% NSSV 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 NSSV 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 evaluation.

SECL-91-429, Revision 1

3. Containment Inte rit Evaluation Relaxation of the Donald C. Cook Units 1 5 2 Technical Specification Main Steam Safety Valve setpoint tolerances from +1N 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 steamline 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 15X 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 20X 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

j SECL-91-429, Revision 1 radioactivity assumed to be present in the reactor coolant, the amount 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.

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

To evaluate the effect of the increased HSSV setpoint tolerance on the Donald C. Cook SGTR analysis, the revised SG safety valve set pressure was lowered by 3X from 1080 psia to 1047.6 psia. This resulted in a slightly higher equilibrium primary-to-secondary break flow (approximately 0.5X),

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 0.2X) because'f 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 HWt.

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 1: 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 0.5N, 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.

SECL-91-429, Revision I

5. Com onent 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 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 stems Evaluation The relaxation of the lift setpoint 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.I and III.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 Risk Anal ses activities af fectin IPE The relaxation of the lift setpoint tolerance for the MSSVs at Donald C. Cook does not adversely affect the Individual Plant Examination (IPE) for the plant. This test does not affect the normal plant operating

SECL-91-429, Revision I 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 ses chan es other tl PE-related The relaxation of the lift setpoint t~.,~ ance for the HSSVs 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 malfunction of equipment important to safety or of equipment that could indirectly affect equipment important to safety.

. ~IL The relaxation of the lift setpoint tolerance for the NSSVs 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 lE, 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 HSSV setpoint tolerance relaxation has no potential for impact to the identification of an unresolved safety question as it would relate to the safety related function of electrical systems of components.

SECL-91-429, Revision 1

11. Technical S ecifications A review of the Donald C. Cook Unit 1 and Unit 2 Technical Specifications was performed to address a change in the lift setpoint 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 +1% and +3% tolerances.

IV. ASSESSMENT OF NO UNREVIEMED SAFETY UESTION The relaxation in the lift setpoint tolerance for the HSSVs at Donald C.

Cook Units 1 and 2 has been evaluated consistent with the requirements of 10 CFR 50.59 and does not involve an unreyiewed safety question on the basis of the following justifications:

1. Will the probability of an accident previously evaluated in the SAR be increased2 No. The +3% tolerance on the HSSV 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 HSSV. The HSSVs 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 HSSV lift setpoint tolerance by 3% above or below the current Technical Specification setpoint value.

SECL-91-429, Revision 1

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 0.2N, 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 ejection) are still applicable.

Therefore, based on the above, there is no increase in the'dose consequences.

3. Hay the possibility of an accident which is different than any already evaluated in the SAR be created'o.

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 lift setpoint tolerance on the NSSVs 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 HSSVs and

SECL-91-429, Revision 1 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 increased7 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 lift setpoint tolerance on the HSSVs 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 increased7 No. As discussed in the response to guestions 2 and 4, there is no increase in the dose release consequences as a result of increasing the as-found lift setpoint tolerance on the HSSVs as defined in the attached safety evaluation.

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

As discussed in guestion 4, an increase in the as-found lift setpoint tolerance on the HSSVs will not impact any other equipment important to safety. Therefore, the possibility of a malfunction of equipment important to safety different than any already evaluated in the UFSAR will not be created.

SECL-91-429, Revision 1 7; Will the margin of safety as defined in the bases to any technical specification be reduced'o.

As discussed in the attached safety evaluation, the proposed increase in the as-found HSSV 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.

SECL-91-429, Revision 1 V. CONCLUSIONS The proposed change to main steam safety valve lift setpoint tolerances from +1% to +3X has been evaluated by Westinghouse. The preceding analyses and evaluations have determined that operation with the HSSV setpoints within a +3% 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 +3% tolerance on the HSSV 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 +1X to +3X does not represent an unreviewed safety question per the definition and requirements defined in 10 CFR 50.59.

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

ii SECL-91-429, Revision 1 VI. REFERENCES

1) Donald C. Cook Units 1 5. 2 Technical Specifications through Amendments 157 and 141, respectively, 10/1/91.

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

ASME, 1983.

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

4) "Donald C. Cook Units 1 5 2 Updated Final Safety Analysis Report (UFSAR), dated through July 1991.

5) ASME Steam Tables, Fifth Edition, 1983.

6) Burnett, 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*-G-0126 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.

SECL-91-429, Revision 1 TABLE 3 UNIT 1 TURBINE TRIP SE(UENCE OF EVENTS ACCIDENT EVENT ~TINE sec Without pressurizer Turbine trip, loss of main 0.0 control (minimum feedwater flow reactivity feedback)

High pressurizer pressure 7.7 reactor trip setpoint reached Rods begin to drop 9.7 Peak pressurizer pressure 10.5 occuls Minimum DNBR occurs Without pressurizer Turbine trip, loss of main 0.0 control (maximum feedwater flow reactivity feedback)

High pressurizer pressure 7.9 reactor trip setpoint reached Rods begin to drop 9.9 Peak pressurizer pressure 10.5 occurs Minimum DNBR occurs

• DNBR does not decrease below its initial value.

SECL-91-429, Revision 1 TABLE 3 (continued)

UNIT 1 TURBINE TRIP SEQUENCE OF EVENTS ACCIDENT EVENT ~TIME sec With pressurizer Turbine trip, loss of main 0.0 control (maximum feedwater flow reactivity feedback)

Peak pressurizer pressure 10.0 occurs Low-low steam generator water 47.1 level reactor trip setpoint reached Rods begin to drop 49.1 Minimum DNBR occurs With pressurizer Turbine trip, loss of main 0.0 control (minimum feedwater flow reactivity feedback)

High pressurizer pressure 12.4 reactor trip setpoint reached 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.

SECL-91-429, Revision 1 TABLE 4 UNIT 2 TURBINE TRIP SE(UENCE OF EVENTS TIME sec mixed, full ACCIDENT EVENT core core Without pressurizer Turbine trip, loss of main 0.0 0.0 control (minimum feedwater flow reactivity feedback)

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 Turbine trip, loss of main 0.0 0.0 control (maximum feedwater flow reactivity feedback)

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.

f t SECL-91-429, Revision 1 TABLE 4 (continued)

UNIT 2 TURBINE TRIP SE(UENCE OF EVENTS TIME sec mixed full ACCIDENT EVENT core core With pressurizer Turbine trip, loss of main 0.0 0.0 control (maximum feedwater flow reactivity feedback)

Peak pressurizer pressure 7.0 7.5 occurs Low-low steam generator water 60. 1 52.8 level reactor trip setpoint reached Rods begin to drop 62.1 54.8 Minimum DNBR occurs With pressurizer Turbine trip, loss of main 0.0 0.0 control (minimum feedwater flow reactivity feedback)

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.

~ ~4 SECL-91-429, Revision 1 DONALD C. COOK UNITS 1 5L 2 INITIAL INPUT PARAMETERS FOR THE SMALL BREAK LOCA EVALUATION OF INCREASING THE MSSV SETPOINT TOLERANCE Table 5 Current Licensing Basis Steam Line Safety Valves per Loop Safety Setpoint Percent Accumulation Flowrate 8 Acc Valve Pressure si Accumulation Pressure si Pressure lbs hr

• 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 in2 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.

SECL-91-429, Revision 1 DONALD C. COOK UNITS 1 8L 2 INITIAL INPUT PARAMETERS FOR THE SMALL BREAK LOCA EVALUATION OF INCREASING THE'SSV SETPOINT TOLERANCE Table 6 MSSV Setpoint Increase Steam Line Safety Valves per Loop Safety Setpoint Pressure Percent Accumulation Flowrate 8 Acc Valve ~NN i R Pressure si Pressure lbs hr

• 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 in2 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.

SECL-91-429, Revision 1 DONALD C. COOK UNIT 1 INITIAL INPUT PARAMETERS FOR THE SHALL BREAK LOCA EVALUATION OF INCREASING THE HSSV SETPOINT TOLERANCE Table 7: Low Pressure, Low Temperature Current HSSV Licensing Setpoint Basis Increase License Core Power1 (HWt) 35882 3250 Total Peaking Factor, Fq 2.32 2.32 Axial Offset (X) +30 +30 Hot Channel Enthalpy Rise Factor, FH 1.55 1.55 Maximum Assembly Average Power, PHA 1.433 1.433 Fuel Assembly Array 15 X 15 OFA Accumulator Water Volume (f) ) 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 Vessel Outlet Temperature (F) 581.71 578.57 RCS Pressure (psia) 2100 2100 Steam Pressure (psia) 564.36 596.48 Steam Generator Tube Plugging Level (X) 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 (psi a) 1860 1860 Safety Injection Signal Setpoint (psia) 1715 1715 Safety Injection Delay Time (sec) 27 27 Safety Injection Pump Degradation (N) 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 Hain Feedwater Isolation Delay Time (sec) 0.0 0.0 Hain Feedwater Valve Closure Time (sec) 8.0 Auxiliary Feedwater Enthalpy Delay Time (sec) 6O~ 272 Main Steam Safety Valve Setpoint (psia) Table 1 Table 2 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 HWt.

Value is based on 102X 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.

SECL-91-429, Revision 1 DONALD C. COOK UNIT 1 INITIAL INPUT PARAMETERS FOR THE SMALL BREAK LOCA EVALUATION OF INCREASING THE MSSV SETPOINT TOLERANCE Table 8: Low Pressure, High Temperature Current HSSV Licensi~g Setpoint Basis Increase License Core Power (HWt) NA 3250 Total Peaking Factor, Fq NA 2.32 Axial Offset (%) NA +30 Hot Channel Enthalpy Rise Factor, FH NA 1.55 Haximum Assembly Average Power, PHA NA 1.433 Fuel Assembly Array NA 15X15 OFA Accumulator Mater Volume (f) ) NA 946 Accumulator Tank Volume (ft ) NA 1350 Hinimum Accumulator Gas Pressure, (psia) NA 600 Loop Flow (gpm) NA 354000 Vessel Inlet Temperature (F) NA 543.63 Vessel Outlet Temperature (F) NA 606.79 RCS Pressure (psi a) NA 2100 Steam Pressure (psia) NA 793.90 Steam Generator Tube Plugging Level (%) NA 15 Haximum Refueling Water Storage Tank Temperature (F) NA 120 Haximum 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 Reactor Coolant Pump Delay Time (sec) NA 4,4 Hain Feedwater Isolation Delay Time (sec) NA 0.0 Hain Feedwater Valve Closure Time (sec) NA 8.0 Auxiliary Feedwater Enthalpy Delay Time (sec) NA 272 Hain Steam Safety Valve Setpoint (psia) NA Table 2 Two percent is added to this power to account for calorimetric error.

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

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

P SECL-91-429, Revision 1 DONALD C. COOK UNIT 2 INITIAL INPUT PARAMETERS FOR THE SMALL BREAK LOCA EVALUATION OF INCREASING THE MSSV SETPOINT TOLERANCE Table 9: Low Pressure, High Temperature Current HSSV Licensing Setpoint Basis Increase License Core Power (HWt) 3413 3250 Total Peaking Factor, F~ 2.34 2.357 Axial Offset (%) +30 +13 Hot Channel Enthalpy Rise Factor, FH 1.644 1.666 Haximum Assembly Average Power, P~A 1.519 1.46 Fuel Assembly Array 17 X 17 V5 Accumulator Water Volume (fg ) 946 946 Accumulator Tank Volume (ft~) 1350 1350 Hinimum Accumulator Gas Pressure, (psia) 600 600 Loop Flow (gpm) 354000 354000 Vessel Inlet Temperature (F) 2 544.41 544.41 Vessel Outlet Temperature (F)2 610.19 610.19 RCS Pressure Including Uncertainties (psia) 2100 2100 Steam Pressure (psia) 2 807.03 807.03 Steam Generator Tube Plugging Level (%) 15 15 Haximum Refueling Water Storage Tank Temperature (F) 120 120 Haximum Condensate Storage Tank Temperature (F) 120 120 Fuel Backfill Pressure (psig) 275 275 Reactor Trip Setpoint (psia) 1860 1860 Safety Injection Signal Setpoint (psi a) 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 Hain Feedwater Isolation Delay Time (sec) 0.0 2.0 Hain Feedwater Valve Closure Time (sec) 8.0 6.0 Auxiliary Feedwater Enthalpy Delay Time (sec) 349 349 Hain Steam Safety Valve Setpoint (psia) Table 1 Table 2 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.

SECL-91-429, Revision 1 D. C. COOK UNIT 1 HSSV SETPOINT TOLERANCE INCREASE SHALL BREAK LOCA EVALUATION TABLE 10 TINE SEqUENCE OF EVENTS

~Time s LPLT LPLT LPHT LPHT w/ HSSV w/o MSSV w/ HSSV w/o MSSV Event 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'oop 643.4 644.7 601.8 608.3 seal core uncovery NA NA NA NA Loop seal core recovery NA NA NA NA Boil-off core 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/ HSSV is main steam safety valve setpoint tolerance increase case at 3250 HWt core power.

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

SECL-91-429, Revision 1 DONALD C. COOK UNIT 1 HSSV SETPOINT TOLERANCE INCREASE SHALL BREAK LOCA EVALUATION TABLE ll

SUMMARY

OF RESULTS LPLT LPLT LPHT LPHT w/ HSSV w/o HSSV w/ MSSV w/o HSSV NOTRUHP 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/H20 Reaction Maximum (%) 3.47 2.47 3.13 1.82 Local Zr/H20 Reaction Location (ft) 11.75 11.75 11.75 11.75 Total Zr/H20 Reaction (N) <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 HWt core power.

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

SECL-91-429, Revision 1 DONALD C. COOK UNIT 2 HSSV SETPOINT TOLERANCE INCREASE SHALL BREAK LOCA EVALUATION TABLE 12 TINE SEQUENCE OF EVENTS

~Time s LPHT LPHT w/ HSSV w/o HSSV Event Break Occurs 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-off core 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/ HSSV is main steam safety valve setpoint tolerance increase case at 3250 HWt core power.

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

SECL-91-429, Revision 1 DONALD C. COOK UNIT 2 HSSV SETPOINT TOLERANCE INCREASE SMALL BREAK LOCA EVALUATION TABLE 13

SUMMARY

OF RESULTS LPHT LPHT w/ MSSV w/o HSSV 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/H20 Reaction Maximum (%) 4.26 4.83 Local Zr/H20 Reaction Location (ft) 11.75 11.75 Total Zr/H20 Reaction (%) <1.0 <1.0 Rod Burst None None Artificial Leak-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/ HSSV is main steam safety valve setpoint tolerance increase case at 3250 HWt core power.

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

75 pSIA 2400 PSIA 03 1840 o51A

'000 iPS;A i 2100 i PSIA 45

~ gglgNTOR SAFETY YALYES OPBI 518 Sl5 588 585 5~8 '15 688 685 613 615 628 625 638 ovg (<F:

eamamm Q~ NomfnaI Tavg ~ 578.7'F Care Lists ts .'(ominat Pr assure 2100 ps.'a DONALD C. COOK UNIT 1 FIGURE la ILLUSTRATION OF OVERTEHPERATURE ANO. OVERPOWER OELTA T PROTECTION

75 OPaT 1922 2250 PSIA PSIA 65

~ 68 4 2000 2%0 PSIA PSIA D

55 SB 45 ITEN GENERATOR SAFETY VALVES OPQl 568 565 578 575 5SS 585 5'RS 5'l5 Sle 685 618 615 628 625 t eve toF)

---

OTaT Protection Lines Cars Thsrssl Safety Ltsits Nominal Vessel Average Temperature ~ 575'F Nominal Pressurizer Pressure 2250 psia DONALD C. COOK UNIT 2 (MIXED CORE)

FIGURE 1b ILLUSTRATION OF OVERTEMPERATURE AND OVERPOWER DELTA T PROTECTION

OPaT 1922 PSIA 2400 PSIA OQ 2000 PSIA 2250 STEN GENERATOR PSIA SAFETY VALVES OPEN 75 588 SBS 598 5~5 688 685 618 615 628 625 638 ov9 toF

---

OTaT Protection Lines Cora Thsrsal Safety Usits

~ 581.3'F Nominal Vessel Average Temperature Nominal Pressurizer Pressure 2100 psia.

OONALO C. COOK UNIT 2 (FULL V5 CORE)

FIGURE lc ILLUSTRATION OF OYERTEHPERATURE ANO OVERPOMER DELTA T PROTECTION

"500 n

500

~

nq <<Vv I

I "70C

'n

• n 2300.

1900.

1800.

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

T ME (SEC) 2'300 .

13QQ, 1600, 1400.

1200.

Jl 1000.

800 70., 80. 90. 100.

Q, 10. 20. 30. 40. 50. 60.

TIME (SEC)

DONALD C. COOK UNIT I FIGURE 2 TURBINE TRIP EVENT MITHOUT PRESSURE CONTROL, HINUHUN REACTIVITY FEEDBACK

0 IO 20 3C 40 50 60 70 80 9C tC~

T ME (SEC) 4,5 X

3.

'i 5 I.S

l. 0 40 lO 10 20 30 50 60 80 9C T-'MK (SEC}

DONALD C. COOK UNIT I FIGURE 3 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, MINUHUM REACTIVITY FEEDBACK

II 680 560 640 620

.

) 63G 580 560 5~0 520 500 0 t0 20 3C 40 50 60 IO 80 u= 9C tC3 T (SEC) 700 680 560 540 520 500' 580 560 540 520 500 10 20 30 40 50 60 70 80 90 tCO T v= (SEC)

I ~

DONALD C. COOK UNIT I FIGURE 4 TURBINE TRIP EVENT MITHOUT PRESSURE CONTROL, MINUMUM REACTIVITY FEEDBACK

x 1 IOQ.

1300.

n 30C. j I

n 300.

700.

600.

500.

10. 20. 30. 40. 50. 60. 70. 80. 90. IOC.

T>MK (SEC) 400 IQ 350 300 250 200 t50 CC 100 50 rn Q

-50 0 10 20 30 40 50 60 10 80 90 ,ICO TlilE (SKC)

DONALD C. COOK UNIT 1 FIGURE 5 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, HININN REACTIVITY FEEDBACK

4p 30 CA IA 25 2P 15 10 5

CO 0

-5

-10 0 10 20 30 ip 50 80 lo SO 90 1OO Tiff (SKC)

ONALD C. COOK UNIT I FIGURE 6 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NININN REACTIVITY FEEDBACK

i I

h 'RAP o Ve "SOC "OC

<< ~CC

~ eel C

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21OC.

230C l 900.

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T!vK (SEC) 2300.

taboo.

t 600 ac

( 400 t 200.

l $ 04,

0. 10, 20. 30, i0. 50. d0, 70. d0. 90. IOC.

T<gK (SKC)

ONALD C. COOK UNIT I FIGURE TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL,,

NXINN REACTIVITY FEEOBACK

1 I

8 Z

10 20 30 i0 50 60 70 80 90 ~CO T'MK (SKC'.5 3.5 3,

2.5 0 l0 20 30 l0 50 60 70 60 90 >CO TlQK (SKC)

ONALD C. COOK UNIT I FI6NE 8 TURBINE TRIP EVENT itITHOUT PRESSNE CONTROL, NXINN REACTIVITY FEEOBACK

M II

530 t 56G 5<0 626 530 C

560 5eQ 520 500 10 20 30 40 50 60 70 80 90 ~CQ T vK (SEC)

~00 680 660 6~0 620 600 9

580 560 540 524 0 i0 20 30 io 50 84 70 80 90 iCA T <SR (MC)

ONllO C. COOK NIT 1 FISuaa 9 TNBIltK TRIP EVENT VITHOuT PRKSSNK CONTROl, NXINN REACTIVITY FEEOBACK

1 c

1 100 1300 300.

900.

700.

600.

500

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71MK (SKC) 400 tQ 350 300 'lir )

' r 250 200 l~

150 100 50 P~

0

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DONALD C. COOK UNIT I FIGURE 10 TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

ac 1000.

QC 900.

800.

700.

SOO.

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

TIME (SEC) 400 350 3OO 250 zoo 150 100 50 0

Mo >0 20 30 io 50 80 >Q 80 90 ioo Tt iC (SEC) 00NAU) C. COOK NIT 2 (NIXED CDRE)

FIGURE 25a TURSINE TRIP EVENT WITHOUT PRESSURE CONTROt.,

NINNN REACTIVITY Ff fDBACK

200 1100.

1300.

300.

900.

700.

600.

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

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

50 10 20 30 40 50 do 70 80 90 100 (SEC) 00NLD C. COOK UNIT 2 (FULL VS CORE)

FIGURE 25b TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NINNN REACTIVITY FEEOBACK

T 40 35 30 CA 25 20 15 4J N 10 V) 0

-5

-10 0 10 20 30 40 50 60 10 80 90 100 TILING (SEC)

OONALD C. COOK UNIT 2 (NIXED CORE)

FIGURE 26a TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NIHNN REACTIVITY FEEOBACK

40 35 30 pn 25 w~ 20 15 W

10 5

CA 0

-5

-10 0 10 20 30 40 50 d0 70 80 90 100 TisC (SCC)

DONALD C. COOK UNIT 2 (FULL V5 CORE)

FIGURE 26b TURBINE TRIP EVENT ltITHOUT PRESSURE CONTROL, HINNN REACTIVITY FEEOBACK

l I

0

1 7nc 2500 250C

~QC

< 3AW

'V

~one

+WC i

'Jl 2 100, 2300.

<900.

1800.

0. 10. 20. 30. 40 50 50 70 d0. 90. 100.

TtsE (SEC) 2300.

)800.

f600.

ce t 400.

l 200.

1000.

10. 20. 30. io. 50. 60. 10. 80. 90. 100.

TiSK (SEC)

ONNU) C. COOK UNIT 2 (NIXEO CORE)

FIGURE 27a TURSM TRIP GENT WITHOUT PRESSURE CONTROL, NXINN REACTIVITY FEEOBACK

I 0

7"-C

'5OC

'Jl "2500

"~CC C

SOC v

') hC gO n

2 tOO 2300.

1900.

l 500.

lO. ZO. 30. 40. 50. dO. 7C. 80, 90. IOO r vE (SKC) 2 3OC

.F900.

h 1500.

>ZOO.

1300.

$ 00 ~

0, t0. 20, 30. 40. M. 00. 70. 80. 90. l00.

r ~E (MC)

OONlLD C. COOK UNIT 2 (FULL Vs CORE)

FIGNE 27b TURBINE TRIP EVENT WITHOUT NESSURE CONTROL, IQXINN REACTIVITY FE'EOBACK

C Z

Q.

>0 20 30 <0 50 60 10 )0 90

>iMK (SEC) 2.4 a 2 2 1.2 0 10 20 30 io 50 6Q 70 6Q 90 tCQ (SEC)

OOOO C. COOK UNIT 2 (NDEO CNE)

FIQNE 28a TNSINE TRiP EVENT WITHOUT NESSNE CNTROL, NXINN REACTIVITY FEEOBACK

C j

Z 4 Z

iO 20 So +0 50 60 To 80 ea tCO 7'QK (SKC) 2 5 l,5 to Zo 30. iO 50 dO 10 aO eC lCa t:~c (sac)

OOOO C. COOK NlT 2 (FULL VS CNE)

FNURE 2ab TNBlNE TllP EVNT MlTHOUT PRESSNE CQiTROL, NXlllN REACTlVlTY FEEDBACK

l < J F E

56C i 540 629 53G 560 540 520 500 0 10 20 30 40 50 d0 70 80 T-'ME 90 (SEC) 700 dao 660 640 620 600 580 580 5<0 520 IO 20 30 40 50 d0 'lO 80 90 ICO (SEC)

ONNU) C. COOK UNIT 2 (NIXEO CORE)

FINRK 29a TNSINE TRIP EVENT 'WITHOUT PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

660 3'0

= .-zc)

I

% /1 P J

53C 560 540 520 500 10 20 30 40 50 d0 70 80 90 'QQ T vK (SKC) 00 380 5~0 520 500 2

580 550 5t0 520 0 io 20 So io 50 dO 10 80 r.~g (sKc) 00lQLO C. COOK UNIT 2 (FULL VS CtWE)

FINRE 29b TNBlNE TRIP EVENT WITHOUT PRESSURE CONTIML, NXINN REACTIVITY FEEDBACK

1 100.

'4J ac 1300.

900.

900.

700.

600.

0. 10. 20 ~ 30 '0.

TIME SO.

(SEC)

60. 74. 80. 90. 100.

300 250 200 150 100 50 W

cR 0

4 10 ZO 34 44 50 60 10 80 90 100 TIhC (SEC)

ONALO C. COOK UNIT 2 (llIXEO CORE)

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

t200 t 100 t300.

300.

300.

700.

500.

500.

10. 20. 30. 40. 50. 60. 70. 80. 90. l00.

T(ME; (SQC) 400 CJ 350 300 250 200 150 100 50 0

0 10 20 30 40 50 dO 70 SO 90 >00 T I ME (SEC)

DONALD C. COOK LNIT 2 (FULL V5 CORE)

FINRE 30b TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NCINN REACTIVITY FEEOBACK

0 20 10 5

QC 0

-5

-10 0 10 20 30 40 50 d0 70 d0 90 100, TiME (SEC)

DNhLD C. COOK UNIT 2 (NIXED CORE)

FIGURE 31a TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NXIHLN REACTIVITY FEEOBACK

20 CJ 15 10 QC 4J 5

-5

-10 0 1O 20 30 iO 50 do 10 eO eo 100 TIME (SEC)

DONALD C. COOK UNIT 2 (FULL V5 CORK)

FIGURE 3lb TURBINE TRIP EVENT WITHOUT PRESSURE CONTROL, NXINN REACTIVITY FEEOBACK

27CC 2600 2500 nn - qOC

'"C v

c n

2 10C.

2300.

1900.

1800 O. 10 20 30 iO 50 80 7C. 80 90 '1OC 1'1MK (SKC) 2300.

1300.

1500.

Ag cx 1400.

1200.

J7 1QOO.

800.

0. 10. 20 '0. 40.

TiMK

50. 80.

(SKC)

10. 80. 90. 10C, OONN C. COOK NIT 2 (IIIXEO CORE)

FINRE 32a TURBINE TRIP EVENT QITH PRESSURE CNTROt.,

NXINN REACTIVITY FEEGBACK

'py

~ <<h t<<

<<v

.50C 5CC o gg(1 t<<f a v I

')he a <<V nn <<lpp C

300 F900

>800

0. lO. 20. 30 '0 T l4E 50 d0.

(SEC)

TO. 50. 90. iOC 2r00.

1300. ~e'lip~<<. ~

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~

it~'500 C

! 40C t 20C, n

'n

>300.

aoo.

l0. 20. 30. 40.

r vc

50. 50.

(sec)

'0. 50. 90. IOC 90NLO C. COOK UNIT 2 (FULL V5 CORE)

FIQURE 32b TNSINE TRIP EVENT ltITH PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

l'

$

8 c 6

.4 C

0.

lO ZO 30 40 SO 60 20 80 9C 'C3 T MK (SEC) t.d l.2 iO 'lO 0 IO 20 30 50 50 80 90 >CO T > hC (MC) r IjONLQ C. COOK UNIT 2 (NIXED CNE)

FI6NE 33a TNSINE TRiP EVENT MITH PRESSNE CNTROL, NXINN REACTIVITY FEEOeaCX

l0 ZQ 30 40 50 60 ~0 80 90 'CQ T MK (SKC) l0 20 30 40 50 60 70 80 9C :3 T vK (SKC)

OONILO C. COOK NIT 2 (FUll VS CORE)

FISm 33b TWNE TRIP EVENT WITH PRESSURE CONTROl, NXINN REACTIVITY FEEDBACK

I

":BC ~

660 520 6 GI 58G a

56Q 5<0 520 500 lQ 20 3Q 40 50 60 10 SQ 9G ~GQ r ~K (SEC)

>'30 680 660 640 620 600 580 560 m

540 520 500 l0 20 30 40 50 14 70 40 90 >CQ r ~c (saci OONAU) C. COOK UNIT 2 (NIXEO CORE)

FI6URE 34~

TURBINE TRIP EVENT MITH PRESQlRE CONTROL, NXINN REACTIVITY FEEOBACK

4g 56G 5~0 t~

I h I+

tI

=:

-"r 560 5cQ 500 l0 20 3C <0 50 60 >0 80 K 'v3 T vE (SEC'30 560 540 520 500 580 560 m

5c0 520 0 10 20 30 40 50 60 10 80 9G ICQ T-~K (SKC)

ONALD C. COOK UNIT 2 (FULL VS CORE)

FI6URE 34b TURBINE TRIP EVENT KITH PRE SSURE CONTROL, NXINN REACTIVITY FEEOBACK

1 100.

N

'J)  ! ."00.

z 300.

900.

700.

500.

500.

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

T:MK (SEC) 300 4J 250 I

4 200 (Z

150 1QQ CX 50 0

-50 10 20 30 40 50 80 70 80 90 100 TiME (SEC)

DONALD C. COOK UNIT 2 (MIXED CORE}

FIGURE 35a TURSINE TRIP EVENT QITH PRESSURE CONTROL, HAXINN REACTIVITY FEEDBACK

'z 1100.

600.

500

0. 10. 20. 30. 40 50. 60. TO. SO. 90. 100.

T'MK (SEC) 400

~n 350 300

<g 250 200 ac 150 100 50 0

0 10 20 30 40 50 80 70 80 90 100 T1MK (SEC)

DONALD C. COOK UNIT 2 (FULL V5 CORE)

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

1 25 20 15 10 OC 5

OC V7 0

OC Q

-10 0 1Q 20 30 iO SO SO 70 eO 9O 1QO T iud (SEC)

DONALD C. COOK UNIT 2 (MIXED CORE)

FIGURE 36a TURBINE TRIP EVENT ttITH PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

25 20 10 ac ac 5

0

-5 10 20 30 40 50 50 70 80 90 1CO TIME (SEC)

OONALO C. COOK UNIT 2 (FULL V5 CORE}

FIGURE 36b TURBINE TRIP EVENT KITH PRESSURE CONTROL, NXINN REACTIVITY FEEOBACK

II h

<<yC 26CC n

'5CC

<<

~ <<C

~ 4 g A (0

<<<<ev i ho C

2."CC.

1300

'doo.

to Zo- 30. <0 50. So. 70. 50. 90. iQQ T"vE (SEC)

"300

>800.

iSOC QC

'4oc.

C

~zoo.

1300.

800.

0. 10. 20. 30. iO. 50, do. >0. do. 30. iOO.

TivE (SEC)

DONAlD C. COOK UNIT 2 (NIXED CORE)

FI6URE 37'URSINE TRIP EVENT MITH PRESSURE CONTROl, NINNN REACTIVITY FEEDBACK

'I 2500 n

"~oo 1

n h )All i '4 C

v n

1)QQ,

[ 600 70.

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

TivE (SEC) 2000.

tSOO.

)600.

I 4QQ.

i 200.

n tao0 ~

0. t0, 20. JO. 40. 54. 60. V0, 80. 90. iOC.

T i%'MC)

DONILD C. COOK NIT 2 (FULL VS CORE)

FIGURE 3Ib TNBINE TRIP EVBIT WITH NESSURE CNTROL, IIINNN REACTIVITY FEEDBACK

0 lO 20 30 <0 50 dQ 7Q 80 9C 1CQ T 4K (SEC) 2,2 10 ZO 30 40 50 d0 TO dO 90 (CO T>QK (SEC)

DCNLO C. CNK UNIT 2 (NIXEO CNK}

FI6NE 38a TURBINE TRIP EVENT itlTH PRESSURE CNTROL, NINNN REKTIVITY FEEDBACK

5t

'0 10 20 30 40 T'MK 50 d0 (SEC) 70 80 90 lCQ 4,5 2.5

'

l0 20 30 - 40 50 80 70 80 90 t00 TIME (SKC)

QOlQLD C. COOK UNIT 2 (FULL N CORE)

FIGNE 38b TURBINE TRIP EVENT ARITH PRESSURE CONTROL, NIlNNll REACTIVITY FEEOBACK

d' 58C

'60 5<Q 520 500 'IQ 10 20 30 ~0 50 80 80 9C :CO I MK (SEC)

~QQ 680 680 6cQ 620 600 2

580 580 540 520 500 t0 20 30 io 50 10 70 80 90 'Ca Ti~K (SEC)

DONALD C. COOK'NIT 2 (MIXED CORE)

FINRE 39a TURBINE TRIP EVENT MITH PRESSURE CONTROL, NI80%N REACTIVITY FEE08ACK

o A

QCV ~

h

~ ~ V C gr VW l

560 S<G 500 0 lG 20 50 <0 50 60 ~0 80 9C 'CQ T MK (SEC) 30 58G 560 a 540 5)h 53G Sao 560 5<0 520 500 0 l0 20 30 40 50 80 10 80 90 100 f i QK (Mc)

GNALO C. COOK UNIT 2 (FULL V5 CORE)

FINRE 3gb TUNItIE TRIP EVENT MITH NESSURE CONTROL, NINNN REACTIVITY FEEDBACK

11OC 1300.

300.

BC'.

700.

SOO.

500.'O.

IO. 20. 30. 40. 50. 60. 70. 80. 90. 100.

T'ME (SEC) 400 350 300 250 QC 200 150 100 0

50 0

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

DONALD C. COOK UNIT 2 (MIXED CORE)

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

11QC

'00 ~

300.

+AC 700.

500 Q. 10. 20. 30. 40. 50. 60. 70. SO. 90, 10C.

T'ME (SEC) 500 4QQ k 100 0

-100 0 10 20 30 40 50 60 70 SO 90 1CO TiMK (SEC)

ONALO C. COOK UNIT 2 (FULL VS CORK)

FIGURE l0b TURBINE TRIP EVENT QITH PRESSURE CONTROL, HINIHN REACTIVITY FEEDBACK

4p 30 25 20 15

/A p4 ip QC D

0

-5

- lp 0 l0 20 30 40 50 60 70 Sp 90 tPP T l MK (SKG)

DONALD C. COOK UNIT 2 (MIXED CORE)

FIGURE 411 TURBINE TRIP EVENT 'IJITH PRESSURE CONTROL, NININN REACTIVITY FEEDBACK

30

'J7 2c 20 15

~A 4 )0 5

10 20 30 io 50 60 ZO 80 eO t C."

TIME (SEC)

DONALD C. COOK UNIT 2 (FULL V5 CORE)

FIGURE 4lb TURBINE TRIP EVENT MITH PRESSURE CONTROL, MINIMUMS REACTIVITY FEEDBACK

SECL-91-429, Revision 1 APPENDIX A SIGNIFICANT HAZARDS EVALUATION

SECL-91-429, Revision 1 SIGNIFICANT HAZARDS EVALUATION DONALD C. COOK UNITS 1 5 2 NSSV LIFT SETPOINT TOLERANCE TECHNICAL SPECIFICATION CHANGE INTRODUCTION:

Pursuant to 10CFR50.92, each application for amendment to an operating license must be reviewed to determine if the proposed change involves a significant hazards consideration. The Commission has provided standards for determining whether a significant hazards consideration exists (10CFR50.92(c)]. A proposed amendment to an operating license for a facility involves no significant hazards consideration if operation 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 AMENDMENT RE 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 +IN to +3M. The currently specified tolerance of +IN of the lift setpoint can be difficult to 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.

SECL-91-429, Revision 1 The ASHE Code requires that the valves lift within IX of the specified setpoint (NB-7512.2). The code also states that the valves must attain rated lift (i.e., full flow) within 3/o of the specified setpoint (NB-7512. 1). This evaluation will form the basis for taking exception to the ASHE 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.

BASIS FOR NO SIGNIFICANT HAZARDS DETERHINATION:

- 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 Hain Steam Safety Valve set pressure tolerance from +IX to +3X on the UFSAR LOCA analyses has been evaluated. In each case the -applicable regulatory or design limit was satisfied. Specific analyses were performed for small break LOCA assuming the current HSSV Technical Specification set pressures plus the proposed additional 3X uncertainty. The calculated peak cladding temperatures remained below the IOCFR50.46 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-91-429, 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 HSSV in mitigating the consequences of an accident. Therefore, changing the HSSV lift setpoint tolerances will have no impact on the containment integrity analysis. In addition, based on the conclusion of the transient analyses, the change to the HSSV tolerance will not affect the calculated steamline break mass and energy releases inside containment.

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

l.

~ A significant increase in the probability or

~

consequences of an accident previously evaluated. ~

Relaxation of the HSSV setpoint tolerance from +IX to +3X 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 HSSVs 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 HSSV in mitigating the consequences of an accident. For the events analyzed, all applicable acceptance criteria were satisfied, and there was no

SECL-91-429, Revision 1 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 HSSV 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 will be created that will increase the challenge to the HSSVs 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 HSSV 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

SECL-91-429, Revision 1 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.

SECL-91-429, Revision 1 APPENDIX B MARKED UP TECHNICAL SPECIFICATION SECTIONS 3.1.L.L All aain steaa Line code safety valves associated vtth each sesv generator shaLL be OPERhSLE, MODE5 1, 2 and 3.

hQZM:

ae Wteh 4 reactor coolant Looys aad associated steaa generaeocs ia oyeraetoa and vieh,oae or aors aata seaaa Line code safety valves inoyerable, oyeraetoa ia lNDN 1, 2 and 3 say yroceed yrovtdad, that vtthta 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, etcher the taoyerable valve Rs restored to QMhb?X status or the Pacer Range Neutron FLux Mt'eeyoiae trty is reduced yer Table 3.7-1; othervtsa, <o in at Lease 80'TANDIT vtehia ehe next I hours an4 tn CO+

58VttOWN viehin ehe follovtai 30 bours. 3g

b. Qtth 3 reactor coolaat Loops and assoctatsd stsaa generals ia oyeratton and vtth one or mre aata stsaa Ltae code safety valves associated vtth an oyerattng looy tnoyerable, oyeraekon in lNDI 3 aay yrocaed yrovtde4, chat vtehtn 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, either ehe taoyerabie valve is restored to QHRQQ aeacus or aha reaceor eriy breakers are oyeae4; oehervtse, be tn COLD 5HUTDORf vtthtn ehe next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

C. The yrovtstoaa of 5yectftcattoa 3.0.4 are not ayylicable.

~ ~

I 4.7.1.1 OPERASLE, Each vtth aatn s~

lift Ltn>> code safety valve sha11 be dsmaaeraead setttnga and orifice stses aa sbova ta Table 4.7 L, ~ in of ehe Ioiler and tres'sure Vessel Code, 1974 ~

accordance vieh Section XX ASAR D. C. OX% UNIT 1 3/4 7 1 AmINmme HO.L2o

TABLE 3. y-l

~l~ "LLSHSLE POMER RANGE NEUTROII FLUE HIGH SETPOIHT IIRVWAKTIII MITH INOPERMLE STEgl lhxima Allowable Poser Range Haxiaa NeaNN of laopeable Safety Nautron flux HIgh Setpoint Valves oa As ati Steaw Saaerator Percent of RATED THERNAL PORN 65.1

n 5%

SV-1 $ 0C5 paly 14 in.

h. aV-l L

40C5 paiy 1C in oe SV 2 5075 paly 16 in.

4o N2 $ 47% paly 1C in 2 Os Qf 3 k$ paly 1C in

~ )

I n

~ %ho l p~4ae ehall eaisel oyoretiIy teapereturo ooraoe~n4 en4 proeaum' to eabieat oonlitione ot tho valve at

V V Iha OttRAblLZTY of eha aatn seeaa Ltna co4a safoey vaLvos ensures ehae the sacondary sysesa pressure vill bo Lkaiead eo viehtn ies dos'.gn yraasuro of LOTS pat) during eha nose severe aneiciyaead sysesa opera.

eional ezanaiene. The aaxhas raltavtng cayactey is associaes4 vizh s eurbina eziy fzoa LO41 RATIO MRHAL t%LL cotnctdane vieh an assumed:as~

i of condansaz haae silk ( ~ no seNs byyaag ea eha condansor) .

~

Zha syectfte4 valve Life saeetnla an4 raltavtnl cayactetos srs in accozdanc ~ vieh eha tequttsaanes of 5aceton JTT of the ASNX Soiloz and prissuro Coda L97L Kdteton. Tha totaL zaltavtng cayactey for all vaLvss on a o ~ seaaa naa a D.LS3.800 Lba/hr vhtch ta ayyroxtaaeeLy of eha toeal sacondary seam flov af L4.L20,000 Lba/hr ae L00% L2'arcane RA~ Ogling. tCQCR. A aLntaa of 2 OPQAILR aafaey vaLvoa yat oyorabLe seaaa gonaraeot ensures that sufftetane talteCng cayactey ta avat La for eha allovabla TSRQLL NQR raaertetton tn Table $ .7 ~ l.

5TARTUt and/or NUN, OPXRAtION ta alleraila vteh safaey val inoyarabla viehtn the Ltateaeiona of eha ACTION rapatreaanea on eha beat ..

of the raduceton. tn secondary syseoa seem ftov and TIKQ. AMER red .

by eha reduced reaceor eriy saeetags of eha Power R45$ a Naueron FLUÃ channals. Tha raaceor erty saeytne raduaetons ara dartvo4 on eha foLLovtng bases:

Fot 4 looy oyaraeton

~ roan X

Mhara:

5t ~ te4scad raaceor ezty saepotne tn yarcane of NATN tHERQt.

8ÃSR V ~ aaxtaa nuaber of tneyarable safaey valvoa par seaaa Line l,2or3.

~ Taeal raltavtnl cayactey af all safaey valvoa yar seaaa Ltna ~ 4,2!8,4SO Lba/beur.

~ Hertaus zoliaviag cayactey of any one safaey valw

~ lS7,690 Lba/hour.

(LO9) ~ Rover Range Naueron flue-Htg Triy 5aeyotne for 4 Loop oyaracton.

0. C. COOC OCT L 5 3/4 )4L hNRfDltEHT NO. lc

3.7.L.L hLL maia sceaa Line code safety ~elves associacea via each ice~

generator shall be 0PQhbA v'.=4 lift settings as specified in Table 3:7-~.

gEJC4gli: slm 4 1 3 ~

he%:

ae Mich 4 reactor coolant loops a@4 associated steca geaeracors ia operation aa4 vtth ceo or lore maia see@a Liaa code.safety valves arable, operation ta NDCS l, 2 aa} 3 lay proceed yrcnrided, that vithi' hours, eieher che taoyerable valve is restored co OfthL1LC status or the ?aver Emcee laacrocL tea Etym Trip Seeyoiac.

is reduced per Table 3.7-L; othaerLae, be Sa at least SC STL%SY vichha ehe aeat C hours ml in COLD SEQTDOII vtthSa the follevfgg 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. i Vteh 3 reactor coolant Looys aa4 assooSate4 steas geaerators bi oyorattoa an4 etch oae or sore aatn scaas Ikon coda safety valves asaoeiate4 etch ca oyerattag leoy Lacerable, operation in MDt 3 aay yrocee4 yeetda4, that vithts 4 bours, either ehe Snoyerabl ~

+ahab Ls reacore4 eo OPXRASLX status or ehe rsaccor crLy breakers are eyeoe4; ocheartae, ba ia COLO $ 5t?DOW vf,ch'an ehe aam 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

e. The yeovtstona of Syocificatioa 3.0.4 are aot applicable.

4.V.l.l % a44tt5eaa1 4.0 5, Sere>>%lee Xayattmeats ocher Chan chose ~red by Z

0. C. CXS NT? 2 3/47 1 AÃ5ÃSQST 50. 82

TASI.E 3. 7-1 HAXIIINALI.SNSl.E POMER RANGE iIE~Ul@} F SETPOIIIT MITll INOPERASI.E 5TEAH ALVKKK QN I}axlmm Allaable p~r Range iiaxlmm Nueber oC le Safety Neutron Flux Ilieh Setpoint Valves oa Percent of RATED TIIERNLL POMER

~ I 2 65.1

"3CC 2600.

2400.

2000.

1800.

1d00.

0. 10. 20. 30 40. 50. d0. 70. d0  %. 10C.

T1>K (SKC) 2300.

1800.

1600.

1400.

1200 ~

80. 90. 10C.

30. 40, 50, 50, VO.

0. 10, 20.

71'SKC j OOIALD C COOK UHlT 1 FI6NE 17 TNSlNE TRIP EVENT ltITH PRESSNE CONTROL, NlNNN REACT? VITY FEEOBACK

25 20 (J

15 10 QC 5

0(

N 0 QC Q

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

DONALD C. COOK UNIT l FIGURE ll TURBINE TRIP EVENT WITHOUT PRESSURE CONTROl, NXINN REACTIVITY FEEDBACK

2500

'A "50C.

5 400

-'pc i

-" 200 n

2 tOC 2300.

1900.

ie00.

t0. 20. 30 40 50. &0. 70. &0. 90 ~pp Ti>K (SEC) 2300.

F800.

t &00.

t400.

I 200.

I GOO, NO.

0. 10. 24. 30. IO. 50. 54. 70. 84. 90. >OC.

r & (SEC)

ONMLD C. COOK lNIT 1 fIQNE 12 TNSINE TRIP EVENT liITH PRESSNE CONTROL.,

NXINN REACTIVITY FEEDVCX

6 2

0.

10 20 30 <0 50 80 TO 80 90 r vc tsac) 3.5 2.5

t. l0 40 4 20 30 54 64 70 80 90 lCQ 7 i& (SEC) 00NLD C. COOK UNIT 1 FI6LNE 13 TNSINE TRIP EVENT WITH PRESQNE CONTROL, NXINN REhCTIVITY FEEDBACK

580 560 5~0 520 580 560 540 520 500 tO 20 30 <0 50 80 20 80 90 lCQ Viue (SKC)

TOO 580 660 d<O 620 500 580 SdO 5io 500 80 90 t0 20 30 40 54 84 20 >CO Ti& (SCC)

OSLO C. CON tSIT I F I6VRf 14 TNSINE TRIP EVNT kITH NESSNK CONTROL, NXINN REACTIYITY FEEDBACK

>>00.

4J 1000.

900.

SOO.

700.

O 600.

500

0. 10. 20. 30. 40. 50. 50. 70. 80. IO. 100.

risc '(sac)

'00 CJ 350 3OO 250 200 150 100 50 C5 0 10 20 30 40 50 60 70 80 90 100 TluE (SEC)

GONLO C. COOK UNIT 2 (FULL V5 CORE)

FIGURE 15 TURBINE TRIP EVENT MITH PRESSURE CONTROL, NXINN REACTIVITY FEEDBACK

20 47 10 QC 5

9j

-10 0 10 20 30 40 50 60 10 80 90 100 TIVE (SEC)

~ ~

DONALD C. COOK UNIT 2 (FULL V5 CORE)

FIGURE 16 TURBINE TRIP EVENT MITH PRESSURE CONTROL, NAXINN REACTIVITY FEEDBACK

TABLE 3. 7-4 STEMI LlNE ShfETV VALVES PER LOOP 810 LlFT SETTlNG GRlFlCE SILE SV-l l065 psig I.. SV-l l065 psig 16 in.~

@. SV-2 )075 psig l6 in.~

4. SV-2 1075 psig l6 in.~

e. SV-3 l015 psiI l6 in.~

Me Hf~se Xi'ressure slell correspoad to ~ieat eoaditions of Ae valve at aoeiaa) eyeratiaI tesyeratwe .aal pressure.

a7 a 7 The OtQAk?UTT ef che acta eceaa Ltne ee4e sefocy velvoe onncoe chac cho oooon4azy eyecoa ytoeeuto vill be 1taice4 ce vtchtn 1101 of Lce 4eetya ycooaure ef 104f yetg 4ctng che eeoc severe anctotyaco4 syecoe, oyegactonal Ctaaaten!. The aeshma>> teLtevtng eayaetcy La aaeoctace4 vich a oahtne Mt'tea 100% Nits TRIAL 85CL eetna54en! v5ch an ace~4 loco f

~ e&hl5anaef heac etna (t e ~ M a~ lyNaa ce che een4anaeT) the eyeetfte4 Mm ltf! eacctngs M teltevtng aayaetctee ate Ln aaaec4ance v5ch che c~tMeoca ef lee!ted lit ef che ASS efWtlet an4 QggggT A Pteeeute Ce4e, NIL.

vie en ye!conc et che A

~

1%71 I4tctea e~

aaxhae seeen4aty The cecal !eitevtng cayaotcy 1Lnea La l),DS,NO Sejm Meb atnto% ef a Onautx eafecy valvea eceaII 6ev tace a! 10K

~ e~

chac autfte5ene aeltevtng eayaetey ta <<vatlable fet che allevable tQRIQ,

~

gen ~acer all rafecy ta a! Jeasc LOS 5RRliiL

~ee NOSER reecztectea LI talle 3.1 l.

StiRtlt col/et NQCL OtQif'IN ta alleveile vtci aafeey valvea taeyerahle vtehta che ltitcacteaa et che i'?N eeystteeeoca ea cd Ni-baaia et !he tHuectea Ln seeeniary aye~

reqetxe4 1'he eo4scei reaecat mid aee!tNIa ef che See!

a~ flm aI4 ~RNAf.

eha55%2aI fe11evtng baaea:

The teaacec'FSQ ac~fisc f04$ 0Ciena ~ 4a!iver Ns che Range'4%

0'f 4 1'fa!taI I (LN)

Nese:

Ne eence& reaeeee el'eeyotnl ta yeeeane et QtQ

~~L 88RL

~5%% nilhef ef Use

~fahla aatecy %livea ~ a~

'.. I e Qalaic Nltevtng eeyaetcy ta Qa. jhyga 1,g4,4g ef aQ <<afeey villa ye! ace f e aallaeeeltivtNI ta Qe. )lear i eayocttg ef aly ae aatecy valve

~ i leep IS)>4'N

~ Swan Raage Neecgea the tety Soeyeta! fet

~ ye!a!tea OXC RCLQL PQÃt i Ng? t a Sla t.i iNK!N~ IO. Q t3'

1, 2

10 20 30 40 50 80 70 d0 9C >CQ T~QK (SCC) 4 5 2.5 1.5 30 IO 50 60 70 d0 90 t 00 0 IO 20 riK (SCC)

DONLD C. COOK UNIT I FI NE 18 TVRSINE TRiP EVENT ARITH PRESSURE CONTROL, NINNN REACTIVITY FEEDBACK

660 622 6)c )

58c 560 5~O 520 500 0 l0 20 50 40 50 60 y0 80 9C tC" T'~K (SEC)

~00 640 560 6<0 620 600

= 560 660 540 520 0 10 20 30 40 50 60 70 80 90 )CQ T i QC (Sgc)

NNMlI) C. CON UNiT 1 FNNE 19 TURIIKE TRIP EVENT 'QITH PRESSNE CONTROL, IIINNNI REACTIVITY FEEDBACK

The safety valve )s OPERABLE w)th a l)ft sett1ng of g3% about the noefna

~alue. H~er, the safetY valve shall be reset to the noe)na] value pic whenever r~ outside the +1% tolerance.

1100 1O00.

à a

900.

'J) 800.

CD 700.

600.

500

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

TiMK (SEC) 500 CJ 4J Vl 400 4

300 M 200 100 Vl 0

cB

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

QONLN C. CO% NIT I FIGURE 20 TURBINE TRIP EVENT WITH PRESSURE CONTROL, HININN REACTIVITY FEEOBACK

25 4l 20 15 10 OC mao 5

5 g

4J

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

ONNLO C. CON UNIT I FIGURE 21 TURBINE TRIP EVENT WITH NESSURE CONTROL, NININN REACTIVITY FEEOSACK

2500.

25OC ~

n

'n :~OC.

~GO C

'v

2OC.

n 2100.

2300.

1900.

1800

0. 10. 20. 30. 40. 50. 60. 70. 60. 90, 1PO ri~K (SKC) 2000.

1800.

1600.

1 F00.

1200.

1000.

0. 10. 20. 30. 40. 50. 80. VO. 60. 90. iOO.

rim (sac)

ONNU) C. COOK UNIT 2 (NIXEO CORE)

FINRE 22a TNIINE TRIP BtENT VITHOuT PRESSNE CONTML, NINNN REACTIVITY FEEOeaCX

9

'TC"

roc I

'gC C

hO 4

43

'1OC

~OC 19OC.

1800, O. 10. ZQ. 30. 10. 50. 60. 70. gQ. 9Q 1QQ r ~E (SgC',

"30C.

13OC 1500.

140C.

1200, 1300.

600. i0. 60. 70, 50. 90.

0. 10. 20. 30, 50. 10C T. K (SEC) tNKL9 C. COOK NIT 2 (NLL VS CORE}

FINE 22b TNSlNE TRlP EVNT MITHOUT PRKS$ QRE CefTROL, NNNll REACTIVITY FEEDBACK

2 1

8 C

d 4

x 2 0

0 10 20 30 +0 50 50 70 b0 90 tCQ TiMK (SKC) 2.d 2.4 i.d 10 20 30 i0 54 60 10 b0 90 >CO risc (sec)

OONLO C. CNK NIT 2

{NlXEO CORE)

FINE 23a TWNE TRIP EVENT WITHOUT PRESQNE CONTROL, NNNN REACTIVITY FKE08ACK

tO ZO 30 +0 50 do 70 80 9C 'CO

~ MK {SEC) 10 20 30 iO 50 do 10 80 9C >Co T: MK (MC)

Oaee C. Cm UNIT 2

~FuLL VS CORa)

FI NE 23b TURBINE TRIP EVENT itITHOUT PRKSSNK CONTROL, NINNY REACTIVITY FEEDBACK

0 580 660 5<0 520 580 560 540 520 500 0 iO 20 30 iO 50 60 70 80 SC lC~

TiSK (SKC) 700 680 680 8<0 o 620 600 9

580 540 11 20 30 40 50 80 'lo 80 90 >00 Tiff (SEC} C DNWLO C. CON NIT 2 (IIIXKO CORE)

FINRE 24a TNSINE TRIP EVNT WITHOUT PRESSNtE CONTROL, NINNN REACTIVITY FKEOBACK

530 560

$ 40 620 53C 56v 5~0 520 500 10 20 30 40 50 60 lO 80 90 tCO T atK (SEC)

Sao 560 6<0 520 500 580 560 5<0 520 0 t4 20 30 IO 50 60 10 60 90 ICQ T K (SKC)

OONhLO C. COOK UNIT 2 (FULL VS CORE)

FI NK 24b TlNSINE TRIP EVENT 'WITHOUT NESSNE CONTROL, NINNN REACTIVITY FEEDBACK

Attachment 4 to AEP:NRC:1159C Page 1 Included in this attachment are two tables. The first table, entitled "Issues Tracking List," is a compilation of the information requests that the NRC made of AEPSC during the April 21, 1992 meeting. Questions that were specific to the Mod 30 instrumentation have been deleted. The second column in this table indicates the file number where the requested information can be found. These files will be provided during the audit.

The second table, entitled "Documentation Tracking List," contains a listing of what is in each file. As explained during the December 1, 1992 meeting, the filing system delineated in this table was developed to ensure that the documentation developed to support this pro]ect addressed the NRC's questions.

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