ML18047A460

Valve Inlet Fluid Conditions for Pressurizer Safety & Relief Valves for B&W 177- & 205-FA Plants, Summary Rept

ML18047A460
Person / Time
Site:	Palisades
Issue date:	03/31/1982
From:	Cartin L, Merchent J, Winks R BABCOCK & WILCOX CO.
To:
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ML18047A442	List: ML18047A440 ML18047A443 ML18047A445 ML18047A446 ML18047A447 ML18047A448 ML18047A449 ML18047A450 ML18047A451 ML18047A452 ML18047A453 ML18047A454 ML18047A455 ML18047A456 ML18047A457 ML18047A458 ML18047A459 ML18047A460 ML18047A461 ML18047A462
References
V102-17, NUDOCS 8207160357
Download: ML18047A460 (120)

Text

VALVE INLET FLUID CONDITIONS FOR PRESSURIZER SAFETY AND RELIEF VALVES FOR B&W 177- AND 205-FA PLANTS NP-RESEARCH PROJECT Vl02-17 (PHASE B)

SUMMARY

REPORT, MARCH 1982 Prepared by BABCOCK & WILCOX Nuclear Power Generation Division P. 0. Box 1260 Lynchburg, Virginia 24505 PRINCIPAL INVESTIGATORS

• L. R. Cartin R. W. Winks J. W. Merchent R. T. Brandt Prepared for PARTICIPATING PWR UTILITIES and ELECTRIC POWER RESEARCH INSTITUTE 3412 Hillview Avenue Palo Alto, California 94304 EPRI Project Manager J. Hosler Nuclear Power Division 8207160357 820401 PDR ADOCK 05000255 P PDR

NOTICE This report was prepared by the organization(s) named below as an account of work sponsored by the Electric Power Research Institute, Inc. (EPRI) and participating PWR Utilities. Neither EPRI, members of EPRI, participating PWR Utilities, the organization(s) named below, nor any person acting on behalf of any of them: (a) makes any warranty, express or implied, with respect to the use of any information, apparatus, method, or process disclosed in this report or that such use may not in-fringe privately owned rights; or (b) assumes any liabilities with respect to the use of, or for damages resulting from the use of, any information, apparatus, method, or process disclosed in this report.

Prepared by:

Babcock & Wilcox Lynchburg, Virginia J

EPRI PERSPECTIVE PROJECT DESCRIPTION This report, developed under RP Vl02-17 in support of the EPRI/PWR Safety and Re-lief Valve Test Program, presents the expected range of fluid inlet conditions for pressurizer safety andrelief.valves utilized in PWR units designed by Babcock &

Wilcox. These conditions are dete:rmined based on consideration of FSAR, extended high-pressure liquid injection, and cold overpressurization events.

PROJECT OBJECTIVE The objective of this report is to assist PWR utilities having Babcock & Wilcox plants in demonstrating that the fluid conditions under which their valve designs are tested as part of the aforementioned program envelop those expected in their unit (s) *

• PROJECT RESULTS FSAR accident analysis events result in challenges to both relief and safety valves under steam conditions with valve inlet pressures as high as 2677 psia. Liquid dis-charge through relief and safety valves is not predicted for FSAR accident events during the time spans evaluated therein.

Extended high-pressure liquid injection events may result in relief and safety valve challenges under steam and water conditions. Liquid temperatures and surge rates for these events range from 400 to 650°F and 0 to 1600 gallons per minute, respec-tively.

Cold overpressurization events may challenge relief valves. They are not expected to challenge PSVs. Liquid discharge is predicted for these events at pressures ranging from 375 to 565 psia with temperatures ranging from338 to 449°F *

• John Hosler, Project Manager Nuclear Power Division iii

• ~

• ABSTRACT The overpressurization transients for Babcock & Wilcox-designed 177FA and 205FA un-its are reviewed to determine the range of fluid conditions expected at the inlet of pressurizer safety and relief valves. FSAR, Extended High Pressure Injection and Cold OVerpressurization events are considered. The results of this review, pre-sented in the fo:rm of tables and graphs, provides input to the PWR Utilities in their justification that the fluid conditions under which their valve designs were tested as part of the EPRJ:/PWR Safety and Relief Valve Test Program are representa-tive of those expected in their unit(s) *

• -- v

• CONTENTS Page

1. INTRODUCI'ION * * * .... 1-1 1.1. Background * * * * * * * .... 1-1

1. 2. Objective 1-1

1. 3. Scope .... 1-2 1.4. Quality Assurance Statement 1-2

2. DESCRIPTION OF B&W DESIGNED NSS .... 2-1 2.1. General Description ..... 2-1 2.2. 177- and 205-FA NSSs

• 2-3

3. TECHNICAL APPROACH *

• 3-1 3.1. General * * * * * * * * .... 3-1 3.2. FSAR/Reload Events

• 3-3 3.3. Cold RCS Pressurization Events 3-6 3.4. Extended HPI Events * * * *

• 3-6 TRANSIENTS/ACCIDENTS THAT CHALLENGE PORVs AND/OR PSVs 4-1 4.1. General * * * * * * * * * * * * * * * * * * * * * * * * *

• 4-1 4.2. FSAR/Reload Report Event * * * * * * * * * * * * * *

• 4-1 4.2.1. Feedwater Malfunction/Decrease in Feedwater Temperature * * * *

• 4-1 4.2.2. Feedwater Malfunction/Increased Feedwater Flow * * * * * * *

• 4-3 4.2.3. Pressure Regulator Malfunction - Decreased Steam Flow * * * * * * * *

• 4-4 4.2.4. Loss of Load * * * * * * * * * *

• 4-5 4.2.5. Turbine Trip With Reactor Trip 4-6 4.2.6. Closure of an MSIV at Full Power 4-8 4.2.7. Loss of Condenser Vacuum at Full Power 4-8

• 4.2.8. Loss of Offsite Power * * * * * * * * * * * * *

• 4-10 4.2.9. Control Rod Bank Withdrawal at Power * * *

• 4-11 4.2.10. Control Rod Bank Withdrawal at Startup 4-13 4.2.11. Control Rod Ejection Accident

• 4-14 4.2.12. Loss of Main Feedwater 4-16 4.2.13. Feedwater Line Break 4-18 4.3. Cold Pressurization Transients * * *

• 4-24 4.3.1. Description of Design Basis for Cold Overpressure Protection Systems * * *

• 4-24 4.3.2. Expected PORV Inlet Fluid Conditions 4-29

4. 4. Extended HPI Injection Events 4-32 4.4.1. General * * * * . * * * * * * * * *

• 4-32 vii

CONTENTS (Cont'd)

Page 4.4.2. Qualitative Evaluation of Plant Conditions * * * * * * *

• 4-32 4.4.3. Results . . .. . . . . . . . . . . . . 4-33

5. FLUID CONDITIONS AT PSV INLET 5-1

6. FLUID CONDITIONS AT PORV INLET

• 6-1

7. REFERENCES

• 7-1 APPENDIX A - Graphic Event Descriptions A-1 List of Tables Table 1-1. B&W Designed NSS Units Examined * * * * *

• 1-3 2-1. Plant Features/Parameters for 177-FA Plants

• 2-3 2-2. Plant Features/Parameters for 205-FA Plants 2-4 3-1.

3-2.

Licensing Basis Documents Reviewed * * * * * * * *

• Transients/Accidents Which Potentially Challenge PORVs

.. 3-2 and/or PS"i/s * * * * * * * * * * * * *

• 3-2 o * * * * * *

• 3-3. Transients/Accidents That Result in Automatic HPI Actuation

• 3-3 4-1. Initial Conditions and Assumptions for Decrease in Feedwater Temperature Transients for 177-FA Plants * * * * * * *

• 4-2 4-2. Initial Conditions for Decrease in Feedwater Temperature Transients for 205-FA Plants * * * * * * * * * * .... 4-3 4-3. Initial Conditions for Increase in Feedwater Flow Transients for 205-FA Plants * * * * * *

• 4-4 4-4. Initial Conditions for 177-FA Plants - Loss of Load Transient * * * * * * * * *

• 4-6 4-5. Initial Conditions for 177-FA Plants - Turbine Trip/

Reactor Trip Transients * * * * * * * * * * * * * * * *

• 4-7 4-6. Initial Conditions for 177-FA Plants - Loss of Condenser Vacuum at Full Power Transients * * * * * * * * * * * * * * .... 4-8 4-7. Initial Conditions for 205-FA Plants - Loss of Condenser Vacuum Transients * * * * * * * * *

• 4-9 4-8. Initial Conditions for 295-FA Plant - Loss of Offsite Power Transient * * . * * * * . * . * * * * . * * * * * .... 4-11 4-9. Initial Conditions for Bank Withdrawal That Result in Limiting System Pressure Conditions * * * * * *

• 4-13 4-10. Initiating Conditions That Result in Limiting Pressure Excursions * * * * * * * * * *

• 4-14 4-11. Pressurizer Safety Valve Inlet Conditions for Rod Ejection Accident * * * *. * * * * * * * * * * * *

• 4-16 4-12. Initial Conditions That Result in Limiting RCS Pressure Conditions for LOFW * * * * * * * * * * *

• 4-18 4-13. FWLB - Initial Conditions That Result in Limiting Pressure Conditions * * * * * * *

• 4-19 4-14. PORV Inlet Condition Resulting From FSAR/Reload Events for 177-FA Plants * * * * * * * * * *

• 4-20 viii

Tables (Cont'd)

Table Page

". 4-15. PORV Inlet Conditions Resulting From FSAR/Reload Events for 205-FA Plants * * * * * *

• 4-21

• 4-16. Safety Valve Inlet Conditions Resulting From FSAR/Reload Events for 205-FA Plants * * * * * * * *

• 4-22 4-17. Safety Valve Inlet Conditions Resulting From FSAR/Reload Events for 177-FA Plants * * * * * * *

• 4-23 4-:.18. Utilization of PORV in Low Temperature Overpressure Protection * * * * * * * * *

• 4-26 4-19. Required Relief Rates for PORV * * *

• 4-26 4-20. Sunmary of Expected PORV Inlet Conditions for the Cold Overpressurization Event Requiring Maximum Relief Rate 4-30 4-21. Evaluation of HPI Induced Refill for 177-FA Plant

• 4-35 4-22. Evaluation of HPI Induced Refill for 205-FA Plant 4-36 4-23. rtPI Flow * * * * * * * * * . * * * * * * * * *

• 4-36 5-1. Bounding Safety Valve Inlet Conditions Resulting From FSAR/Reload Events for 177- and 205-FA Plants * * * *

• 5-1 5-2. Bounding Safety Valve Inlet Conditions Resulting From Extended Operation of HPI for 177-FA Plants * * * * *

• 5-2 5-3. Bounding Safety Valve Inlet Conditions Resulting From Extended Operation of HPI for 205-FA Plants

• 5-2 6 Bounding PORV Inlet Conditions Resulting From FSAR/Reload Events for 177- and 205-FA Plants 6-1 6-2. Bounding PORV Inlet Conditions Resulting From Extended HPI Operation Following FSAR/Reload Events for 177- and 205-FA Plants * * * * * * * * * * * * * * * *

• 6-2

6-3. PORV Inlet Conditions Resulting From Cold Pressurization Events for 177-FA Plants ************* 6-3 Sequence of Events for Decrease in Feedwater Temperature

• ~:: Transients for 177-FA Plants * * * * * * * * * * * * * *

• Sequence of Events for Decrease in Feedwater Temperature Transients for 205-FA Plants * * * * * * * * *

• A-2 A-4 Sequence of Events for Increase in Feedwater Flow for 205-FA Plant * * * * * * * * *

• A-6 Sequence of Events for Loss of Load Transient for 177-FA Plants * * * * * * * * * * * * * *

• A-8 A-5.

A-6.

Sequence of Events for Turbine Trip/Reactor Trip Transient for 177-FA Plants * * * * * * * * * *

• Sequence of Events for Loss of Condenser Vacuum

.. A-10 Transients for 205-FA Plants * * * * * * * *

• A-12 A-7. Sequence of Events for Loss of Offsite Power for 205-FA Plants * * * * * * * * * * * * *

• A-14 A-8. Sequence of Events for Rod Bank Withdrawal From Fu~l Power A-16 A-9. Sequence of Events for Rod Bank Withdrawal From Low Power * *

• A-18 A-10. Sequence of Events for Rod Bank Withdrawal From Rated Power A-20 A-11. Sequence of Events for Rod Bank Withdrawal From 15% Power * * * * * *

• A-22 A-12. Sequence of Events for Rod Bank Withdrawal at Startup Accident A-24 A-13. Sequence of Events for Rod Bank Withdrawal at Startup Accident * * *

• A-26 A-14. Sequence of Events for Rod Ejection From HFP * * *

• A-28 A-15. Sequence of Events for Rod Ejection From HZP With Reactor Trip on High RCS Pressure * * * * * * * * * * * * * * * *

• A-30 A-16. Sequence of Events for Rod Ejection From HZP With Reactor Trip on High Flux . . . * . . * . * * * * . * . * . . . . . . * .

• A-32 A-17. Sequence of Events for Rod Ejection at HFP-BOL A-34 A-18

• Sequence of Events for Rod Ejection From HZP-BOL A-36 A-19. Sequence of Events for Rod Ejection From BOL-HLP A-37 ix

Tables (Cont'd)

Table Page A-20.

A-21.

A-22.

Sequence of Events for LOFW on 177-FA Plants With Reactor Trip on High RCS Pressure * * *. * * * *

• Sequence of Events for LOFW on 177-FA Plants With Anticipatory Reactor Trip * * * * * * * * * * * * * * * * * *

• Sequence of Events for LOFW on 205-FA Plants With Reactor Trip on High Pressure * * * * * * * * *

• A-39 A-41 A-43 A-23. Sequence of Events for LOFW ori 205-FA Plants With Anticipatory Reactor Trip * * * * * * * * * * * * * * * *

• A-45 A-24. Sequence of Events for FWLB * * * * * * * * * * *

• A-47 A-25. Sequence of Events for FWLB on Operating Plants

• A-49 A-26. Sequence of Events for FWLB * * * * * * * * * *

• A-51 List of Figures Figure 2-1. Typical B&W NSS Unit * * * * * * * * * * * * * * * * * * * * *

• 2-2 4-1. Projected Pressure Response for Very Small LOCA That Repressurizes RCS to PORV or PSV Lift Setpoint in 177-FA Plants * * *

• 4-12 4-2. Projected Pressurizer Mixture Level for Very Small LOCA That Repressurizes RCS to PORV and PSV Lift Setpoint in 177-FA Plants 4-13 A-1. Selected Pressurizer Parameters for Decrease in Feedwater Temperature Transient for 177-FA Plants * * * * * * * * *

• A-3 A-2. Selected Pressurizer Parameters for Decrease in Feedwater Temperature Transient for 205-FA Plants * * * * * * * * * *

• A-5 A-3. Selected Pressurizer Parameters for Increase in Feedwater Flow Transient for 205-FA Plants * * * * * * * *

• A-7 A-4. Selected Pressurizer Parameters for Loss of Load With Reactor Runback Event for 177-FA Plants * * * * * *

• A-9 A-5. Selected Pressurizer Parameters for Turbine Trip With Reactor Trip Transient for 177-FA Plants * * * * * *

• A-11 A-6. Selected Pressurizer Parameters for Loss of Condenser Vacuum at Full Power Transient for 205-FA Plants * * *

• A-13 A-7. Selected Pressurizer Parameters for Loss of Of fsite Power at Full Power Transient for 205-FA Plants * * * * * * *

• A-15 A-8. System Response for Rod Bank Withdrawal at HFP Accident for 177-FA Plants * * * * * * * * * * * * * * * * * * *

• A-17 A-9. System Response for Rod Bank Withdrawal From Low Power Accident for 177-FA Plants * * * * * * * * * * * * .... A-19 A-10. System Response for Rod Bank Withdrawal Accident at HFP Accident for 205-FA Plants * * * * * * * * * * * * *

• A-21 A-11. System Response for Rod Bank Withdrawal From Low Power Accident for 205-FA Plants * * * * * * * * * * *

• A-23 A-12. System Response for Rod Bank Withdrawal at Startup Accident for 177-FA Plants * * * * * * * * * * * *

• A-25 A-13. System Response for Rod Bank Withdrawal at Startup Accident for 205-FA Plants * * * * * * * * * * * *

• A-27 A-14. System Response for Rod Ejection at BOL-HFP Accident for 177-FA Plants * * * * * * * * * * * * * * * * * *

• A-29 A-15. System Response for Rod Ejection at BOL-HZP With High Pressure Reactor Trip Accident for 177-FA Plants A-31 x

---

~

Figures (Cont'd)

P~e Figure A-16. System Response for Rod Ejection at BOL-HZP With High Flux Trip of Reactor Accident for 177-F~ Plants

• A-33

• A-17. system Response for Rod Ejection at BOL-HFP Accident for 205-FA Plants * * * * * * * * *

• A-35 A-18. System Response for Rod Ejection at BOL-HZP Accident for 205-FA Plants * * * * * * * *

• A-36 A-19. System Response for Rod Ejection at BOL-HLP Accident for 205-FA Plant * * * * * * * *

• A-38 A-20~ System Response for LOFW With Reactor Trip on High RCS Pressure Accident for 177-FA Plants * * * *

• A-40 A-21. System Response for LOFW With Anticipatory Reactor Trip Accident for 177-FA Plants * * * * * * * * *

• A-42 A-22. *system Response for LOFW With Reactor Trip on High RCS Pressure Accident for 205-FA Plants * * * * * * *

• A-44 A-23. System Response for LOFW With Anticipatory Reactor Trip Accident for 205-FA Plants * * * * * * * * * *

• A-46 A-24. System Response for FWLB for 177-FA Plant * * * *

• A-48 A-25. System Response* for FWLB Accident for 177-FA Plants A-50 A-26. System Response for FWLB Accident for 205-FA Plants *

• A-52

• xi

SUMMARY

Following the Three Mile Island Unit 2 (TMI-2) incident, the Nuclear Regulatory Commission (NRC), in their NUREG-0578 1 , recommended that utilities operating and in process of constructing pressurized water reactor (PWR) power plants develop a test program to demonstrate the operability of power-operated relief valves (PORVs) and self-actuated safety valves (PSVs) used in the protection of reactor coolant systems..

The recommendations of NUREG-0578 were later required by NUREG-0737 2

• In response to NUREG-0578 and NUREG-0737 requirements, the Electric Power Research Institute (EPRI) was assigned the responsibility of conducting a comprehensive test program to encompass the various types of PORVs and safety valves used by participating utilities. The primary objective of that program as defined in reference 3, is "to evaluate the performance of each of the various types of reactor coolant system safety and relief valves in PWR plant service for the range of fluid conditions under which they may be required to operate." For purposes of the EPRI valve test program, fluid conditions under which the PORV and safety valves may be required to operate refer to the valve inlet fluid conditions that are predicted in conventional PWR licensing analyses.

Each PWR licensee or applicant is required to provide evidence that the fluid condi-tions under which EPRI tested the PORVs and safety valves are representative of the conditions applicable to their specific units. To ensure that the fluid conditions selected are representative, EPRI contracted with the PWR nuclear steam system (NSS) vendors to provide the required fluid conditions under which t~e valves would be ex-pected to operate. As an NSS vendor, Babcock & Wilcox (B&W) was contracted to pro-vide EPRI with the expected pressurizer safety valve (PSV) and PORV inlet fluid con-ditions based on existing FSAR/reload report transient analyses, which form the licensing basis of the B&W 177- and 205-fuel assembly (FA) units.

The objective of the work to be performed under this contract was to provide a re-port, suitable for NRC submittal, that would accomplish the following:

• s-1

Provide bases for the test conditions for the EPRI valve test program.

Be a reference document for use by licensees of 177- and 205-FA units as evidence that the EPRI valve test program test conditions were represen-tative of the conditions expected to be met in plant for the valves tested.

To accomplish the contract objectives, it was necessary to identify the events that result in PORV and/or PSV actuation. In PWR plant designs, three types of events challenge PORV and/or PSV: (1) typical FSAR transient/accident, (2) cold RCS pres-surization transients, and (3) transients resulting from extended operation of the high-pressure injection (HPI) system following initiation caused by either a typical FSAR transient/accident or inadvertent valve actuation while the plant is at power.

The following approach was taken to identify the bounding valve inlet fluid condi-

• tions for the 177- and 205-FA units PORVs and PSVs:

The latest amendment of the SAR was reviewed on an NSS unit-by-unit basis to determine which transient/accidents were considered in es-tablishing the licensing basis of that unit.

Those transients/accidents identified as licensing basis events were then reviewed generically to determine whether they would be predicted to challenge the PORVs and/or PSVs or result in automatic actuation of HPI.

A unit-by-unit review of existing analyses was performed to determine the expected valve inlet fluid conditions for each transient/accident identified to challenge the PORVs and/or PSVs.

For each identified event that resulted in automatic actuation of the HPI system, a qualitative evaluation was performed to determine bound-ing plant conditions that could evolve as a result of extended opera-tion of the HPI system. In addition, consideration was given to the conditions resulting from spurious HPI actuation at power.

For each 177-FA unit that utilizes the PORV as part of its low-tem-perature overpressure protection system, the applicable overpressure report was reviewed to determine the bounding PORV inlet fluid condi-tions.

The results of the reviews listed above were a compilation of expected PORV and/or PSV inlet fluid conditions from the existing analyses that form the units' licensing bases. Since this compilation was done on a unit-by-unit basis, the bounding fluid inlet conditions were then identified for each of the three types of events.

results of the compilation of bounding valve inlet fluid conditions fulfills the S-2 The

objectives of this contract. That is, the results reported in this document are acceptable for use as a basis for justification of the EPRI valve test program test conditions for valves tested for B&W 177- and 205-FA units. In addition, the re-sults compiled in this report are presented o~ a plant type basis, i.e., for 177-and 205-FA plants, in order to make this a reference document for use by the affect-ed licensees in providing evidence that the EPRI test conditions enveloped their valves.

The B&W 145-FA unit design was not considered in this report because the final li-censing bases for the 145~FA design have not been established. The final design and licensing bases for that unit will be established based on conservative assumptions developed with input from EPRI valve test program results.

1 TMI-2 Lessons Learned - Task Force Status Report and Short-Term Recommendations,

• NUREG-0578, u. s. Nuclear Regulatory Commission, July 1979.

2 clarification of TMI Action Plan Requirements, NOREG-0737, U. s. Nuclear Regulatory

• 3 Commission, November 1980.

Program Plan for the Performance Testing of PWR Safety and Relief Valves, Rev 1, Electric Power Research Institute, July 1, 1980.

S-3

Section 1 INTRODUCTION This report presents the results of an evaluation performed by Babcock & Wilcox (B&W) under contract to the Electric Power Research Institute (EPRI).

1.1 BACKGROUND

Following the Three Mile Island Unit 2 (TMI-2) incident, the Nuclear Regulatory Commission (NRC) published NUREG-.0578, "TMI-2 Lessons Learned - Task Force Status

• Report and Short-Term Recommendations," which recommended that utilities operating and in the process of constructing pressurized water reactor (P~1R) power plants de-velop a performance test qualification program for power-operated relief valves (PORVs) and self-actuated safety valves (PSVs) used in the protection of reactor coolant systems. 1 The recommendations of NUREG-.0578 were later required by NUREG-0737. 2 In response to NUREG-.0578 and NUREG-.0737 requirements, EPRI was assigned the responsibility of conducting a comprehensive test program to demonstrate the opera-bility of the various types of PORVs and safety valves used by participating utili-ties. The primary objective of that program, as defined in EPRI's "Program Plan for the Performance Testing of PWR Safety and Relief Valves," is "to evaluate the per-formance of each of the various types of reactor coolant system safety and relief valves in PWR plant service for the range of fluid conditions under which they may be required to operate." 3 For purposes of this test program, fluid conditions refer to the fluid conditions that are prescribed in conventional PWR licensing analyses (PSAR and FSAR). Specifically, each PWR licensee or applicant will be required to provide evidence that the fluid conditions under which EPRI tests the PORVs and PSVs are representative of those prescribed in the applicable licensing document~. To ensure that the fluid conditions selected for testing were representative, EPRI con-tracted with the nuclear steam system (NSS) vendors to provide the required fluid conditions under which the valve tests would be performed.

1.2 OBJECTIVE The primary objective of this evaluation, the results of which are documented in this report, is to formally document the expected range of fluid inlet conditions to

• which the PORVs and PSVs may be subjected.

1-1 The range of conditions will be based

on FSAR analyses and others that form the licensing basis of B&W 177- and 205-FA NSSs.

1.3 SCOPE The evaluation documented in this report is limited to FSAR analyses for B&W 177-and 205-FA NSSs, cold pressurization, and extended HPI events expected to challenge the PORV and/or PSVs. Anticipated transients without scram (ATWS) and plant condi-tions evolving due to a complete loss of feedwater are not covered in this evalua-tion. Table 1-1 lists the NSS units addressed by this evaluation and report.

1.4 QUALITY ASSURANCE STATEMENT This document was prepared in accordance with B&W NPGD Quality Assurance Manual 19A-N.1. The Quality Assurance Program defined within Manual 19A-N.1 expresses the philosophy of the Nuclear Power Generation Division of the Babcock & Wilcox Company.

Manual 19A-N.1 conforms to the requirements of the ASME Code, 1980 Edition (includ-ing the Summer and Winter addenda). It also complies with the requirements of the Code of Federal Regulations 10 CFR SO, Appendix B, and applicable ANSI standards.

1-2

Table 1-1. B&W Designed NSS Units Examined Operating NSS unit Plant status cycle(a) 177-FA Units Oconee 1 Operating 6 Oconee 2 Operating 5 Oconee 3 Operating 6 Three Mile Island Unit 1 Uot operating 5 Three Mile Island Unit 2 Not operating 1 Crystal River 3 Operating 3 Rancho Seco Operating 5 Arkansas Nuclear One-1 Operating 5 Davis-Besse Operating 2 Midland 1 Under construction N/A Midland 2 Under construction N/A 2os~FA units Bellefonte 1 Under construction N/A Bellefonte 2 Under construction N/A

• WNP 1 WNP 4 (a)

Under construction Under construction Fuel cycle as of July 1, 1981.

N/A N/A 1-3

• section 2 DESCRIPTION OF B&W DESIGNED NSS 2.1 GENERAL DESCRIPTION The B&W nuclear steam system (NSS) design comprises a pressurized water reactor (PWR), the reactor coolant system (RCS), and associated auxiliary fluid systems.

The RCS (Figure 2-1) is arranged in two closed coolant loops connected in parallel to the reactor vessel. Each loop contains two RC pumps and a once-through steam generator (OTSG). An electrically heated pressurizer is connected to one of the loops.

The RCS is designed to contain and circulate reactor coolant at pressures and flows necessary to transfer the heat generated in the reactor core to the secondary fluid in the OTSGs. In addition to serving as a heat transport medium, the coolant also serves as a neutron moderator and reflector and as a solvent for the soluble boron used in chemical shim reactivity control.

The reactor is controlled by a coordinated combination of chemical shim and mechani-cal control rods. Chemical shim is in the foJ:m of soluble boron or demineralized water additions through the makeup and purification system (MU&PS).

The reactor core consists of uranium dioxide pellets slightly enriched in uranium-235. The pellets are enclosed in Zircaloy tubes with welded end plugs; the tubes are positioned in a square array assembly. There are either 177 or 205 fuel assem-blies arranged in a lattice array approximating a cylinder. Mechanical control rods placed at selected locations in the array provide reactivity control in conjunction with the chemical shim. The control rods are clusters of stainless steel-clad neu-tron adsorbers that move within the fuel assembly guide tubes.

The reactor vessel and internals contain and support the fuel and control rods and direct the reactor coolant through the core. The cylindrical reactor vessel has hemispherical heads and is made of low-alloy steel clad with stainless steel. The upper reactor vessel head is secured to the vessel by stud bolts that allow its removal for refueling and inspection. Control rod drive mechanisms (CRDMs), which position the control rods vertically, are mounted on the upper head.

2-1

~

I I QUENCH STEAM I I

TANK I

~---PRESSURIZER OTSG A OTSG B RC PUMPS (2) RC PUMPS (2)

Figure 2-1. Typical B&W NSS Unit The steam generators are B&W's once-through design. They are vertical, straight-tube, tube-and-shell components with reactor coolant on the tube side and feedwater on the shell side.

The RC pumps are vertical, single-stage, centrifugal pumps equipped with controlled-leakage shaft seals. Each pump is driven by an induction electric motor equipped with a flywheel to provide stored energy for flow coastdown in the event of loss of electric power to the pumps.

The vertical, cylindrical pressurizer vessel has hemispherical heads and is equipped with electric heaters and spray nozzles for system pressure control. It is con-nected to one RC loop by surge piping to the hot leg of the loop and by spray piping to the RC pump discharge side of the cold leg. The differential pressure across the reactor vessel provides the driving force for spray flow.

2-2 The electric heaters

maintain the pressurizer water at the desired RCS pressure saturation temperature.

The resulting steam is confined in the upper portion of the pressurizer. This steam bubble provides a surge chamber that aids in maintaining a relatively constant sys-tem pressure during RCS volume changes that may occur during transients. The pres-surizer spray serves to condense steam for control of increasing pressure. The RCS safety and relief valves for overpressure protection are connected to the upper portion of the pressurizer. Two ASME Code PSVs are connected to the pressurizer to relieve system overpressure. An additional PORV is provided to limit the lifting frequency of the Code PSVs. The valves discharge to the RC drain tank (quench tank) within the containment.

The RCS main loop piping is made of carbon steel clad with stainless steel. Auxil-iary piping, such as the pressurizer surge and spray lines, are made of stainless steel.

The reactor coolant is pumped from each of the four RC pumps through loop piping (cold legs) to the four reactor vessel inlet nozzles. Coolant flows down an annulus formed by the inside reactor vessel walls and the reactor internals. The flow di-rection changes in the lower reactor vessel head, is heated in the core, and passes to the two reactor vessel outlet nozzles through another series of baffles. The heated water exits the reactor vessel and flows to the upper head of the OTSG via the hot leg piping. Passing down through the steam generator tubes, the coolant transfers heat to the secondary system water producing superheated steam. The cool-ant then flows from the lower head of the OTSG to the RC pump suction to complete the cycle.

2.2 177-FA AND 205-FA NSSs Tables 2-1 and 2-2 provide plant features/parameters unique to the B&W 177- and 205-FA designs, respectively.

Table 2-1. Plant Features/Parameters for 177-FA Plants Feature/parameter Parameter range Fuel assemblies 177 Rated power level, MWt 2452-2772 3 11,817-12,096 Coolant volume, ft Primary system flow, 10 6 lb/h 131.32-137.9

-- 2-3

Table 2-2. Plant Features/Parameters for 205-FA Plants Design power level, MWt Feature/Earameter 3600 3800 Fuel assemblies 205 205 RCS coolant volume, ft 3 13,019 13,477 6

Primary system flow, 10 lb/h 156.24 156.24 2-4

section *3 TECHNICAL APPROACH 3.1 GENERAL In PWR plants there are generally three types of transients/accidents for which the PORVs and/or pressurizer safety valves (PSVs) may be challenged to operate:

Typical FSAR transients/accidents.

Cold RCS pressurization transients.

Transients resulting from extended operation of the high pressure injection (HPI) system following initiation caused by a typical FSAR transient/accident.

Each of these transient/accidents are expected to result in a range of fluid con-ditions at the PORV and PSV inlets. The objective of this report is to document those ranges of fluid conditions which can be expected to exist at the inlets to the pressurizer valves during valve actuation as a result of the three types of transient/accidents listed above.

On an NSS-specific basis the FSAR analyses (chapter 14 or 15 as appropriate) , in-cluding consideration of the most recent licensing base and reload analysis per-formed by B&W, were reviewed. From this review, the transients/accidents were identified that would possibly result in a challenge to those PORVS and/or PSVs, and/or result in automatic actuation of HPI. Table 3-1 provides the licensing basis source documents reviewed for each plant.

3-1

Table 3-1. Licensing Basis Documents Reviewed Plant Source document Oconee 1, 2, 3 FSAR through Amendment 45 and low temperature overpressure protection (LTOP) submittal dated 4/01/77 TMI-1 FSAR through Amendment 50 and LTOP submittal dated 3/22/77 TMI-2 FSAR through Amendment 66, LTOP in FSAR Crystal River 3 FSAR through Amendment 53 and LTOP submittal dated 2/17/77 AN0-1 FSAR through Amendment 59 and LTOP submittal dated 2/22/77 Rancho Seco FSAR through Amendment 29 and LTOP submittal dated 3/17/77 Davis-Besse FSAR through Amendment 44 Midland 1, 2 FSAR through Amendment 92, LTOP in FSAR Bellefonte 1, 2 FSAR through Amendment 20, LTOP in FSAR WNP-1,4 FSAR through Amendment 24, LTOP in FSAR Table 3-2 lists those transients/accidents that were identified during the licensing

.basis source document review as having the potential for challenging the PORVs and/

or PSVs. Table 3-3 lists those transients/accidents that were identified as result-ing in the automatic actuation of HPI.

Table 3-2. Transients/Accidents Which Potentially Challenge PORVs and/or PSVs FSAR Chapter 14/15 Accident NO.

1.1 Feedwater (FW) system malfunction decrease in FW temperature 1.2 FW system malfunction increase in FW flow 2.1 Pressure regulator malfunction resulting in de-creased flow 2.2 Loss of load 2.3 Turbine trip (with reactor trip) 2.4 MSIV closure at full power 2.5 Loss of condenser vacuum 3-2

Table 3-2. (Cont'd)

FSAR Chapter 14/15 Accident No.

2.6 Loss of all power 2.7 Loss of normal feedwater 2.8 FW line break 4.1 Rod bank withdrawal from subcritical condition (startup accident) 4.2 Rod bank withdrawal from power 4.3 Rod drop 4.4 RC punp startup 4.6 Boron dilution 4.8 Rod ejection 6.5 Loss-of-coolant accident (LOCA) spectr.um Table 3-3. Transients/Accidents That Result in Automatic HPI Actuation FSAR Chapter 14/15 Accident No.

1.3 Steam pressure regulator malfunction increasing steam flow 1.5 Steamline break 2.8 Feedwater line break 5.1 Inadvertent operation of ECCS during power operation 6.1 Inadvertent opening of PSV 6.2 Instrument line break 6.5 Loss-of-coolant accident (LOCA) 3.2 FSAR/RELOAD EVENTS For the transients/accidents identified in Table 3-2 to challenge the PORVs and/or PSVs, the existing analyses that were used in establishing the licensing basis of each unit were reviewed in detail. From this spectrum of transients/accidents, the following were developed:

3-3

A generic event description that includes the order and approximate time duration of each fluid state that could exist at the valve in-lets.

Typical NSS response characteristics for the B&W 177- and ~05-FA units1 e.g., pressurizer pressure, surge line flow, surge flow tem-NSS perature, pressurizer level, pressurizer pressurization rate, and possible fluid state at the valve inlets.

Representative values of the PORV and PSV inlet conditions for the B&W 177- and 205-FA NSS units. Included are valve inlet pressure ramp rates, maximum pressurizer pressure, and the valve inlet fluid state.

A wide spectrum of existing analyses covering major overpressurization events were examined in detail for the following classes of events that may actuate the PSVs:

Loss of feedwater.

Feedwater line break.

Rod bank withdrawal from subcritical condition (startup).

Rod bank withdrawal from power.

Rod drop.

Rod ejection.

Boron dilution.

RC pump startup.

For example, a loss of feedwater event was examined in which a reactor trip resulted from either high RCS pressure or an anticipatory reactor trip (i.e., a reactor trip that occurs prior to high RCS pressure). The plant response to these two similar events is very different. By surveying many such transients, bounding fluid con-ditions for the valve inlets were selected that are representative of the events being reviewed.

The examination results for the following major overpressurization events are pre-sented in section 4:

Loss of feedwater.

Feedwater line break.

Rod bank withdrawal from subcritical condition (startup).

Rod bank withdrawal from power.

Rod ejection.

3-4

The examination of the remaining three potential major overpressurization events (control rod assembly drop, boron dilution, and startup of inactive RC pumps) re-vealed that these events either did not challenge the valves or the valve inlet con-

• ditions were bounded by one of the other transients/accidents.

challenge the PORV.

Specifically, the control rod assembly drop transient does not result in RCS pressure high enough to Boron dilution, a reactivity addition transient, is bounded by the rod withdrawal transients in that it adds less reactivity to the reactor than does a rod withdrawal incident. For the RC pump startup, the peak RCS pressure is only slightly above the PORV lift pressure and is, therefore, bounded by other tran-sients that more severely challenge the PORV. Therefore, specific results for these three transients are not presented.

The LOCA analyses reviewed were those covering the stuck-open PORV following an in-advertent or accidental actuation and a loss of main feedwater resulting in stuck open PORV transients; it was detennined that these events would not cause the RCS to repressurize to the PSV setpoint. The results of the two PORV LOCAs reviewed are not presented because the PSVs were not challenged. Larger LOCAs were not consid-ered because they are not expected to challenge the PSVs *

. The remainder of the transients/accidents listed in Table 3-2 were examined on a plant-by-plant basis for the 177- and 205-FA plants; they are FW system malfunction, decrease in FW temperature.

FW system malfunction, increase in FW flow.

Pressure regulator malfunction, decrease in steam flow *

. Loss of load.

Turbine trip (with reactor trip).

Main steam isolation valve closure at full power.

Loss of condenser vacuum.

Loss of ail power.

The results of this examination are presented in section 4.

In analyzing those transients/accidents listed in Tables 3-2 and 3-3, the PORV was assumed to be inoperative for the major RCS overpressurization events. This is a conservative assumption in that it allows the RCS pressure excursion to continue beyond the PORV setpoint before any RCS pressure relief is assumed; i.e., the ear-liest RCS pressure relief is the opening of the PSVs. However, if the PORV is not de-energized or valved out of the system, it would actually be expected to operate during such events. Therefore, to conservatively bound the PORV inlet fluid 3-5

conditions, the results of the transients/accidents for which the PORV is assumed not to operate are imposed on the PORV.

3.3 COLD RCS PRESSURIZATION EVENTS The PORV is used as part of the cold overpressurization protection system only on the B&W 177-FA plants. One 177-FA unit (Davis-Besse) does not use it as a cold overpressurization device. It should be noted that the PSVs are never challenged during cold overpressurization events.

The design basis documents for cold overpressurization protection, as shown in Table 3-1, were reviewed on an NSS unit-by-unit basis for the affected B&W 177-FA unitso From this documentation review, the following were developed:

A description of the design basis, i.e., equipment utilized and de-sign transients/accidents assumed, for cold overpressure protection systems for each 177-FA NSS \.ll'lit that is effected.

A summary of the expected PORV inlet conditions for the transient/

accident that requires the highest relief rate, including the ap-proximate duration of each fluid state that would exist at the valve inlet, ranges of surge rates into the pressurizer, and the liquid surge temperature.

The results of this review are presented in section 4.

3. 4 EXTENDED HPI EVENTS Each transient/accident identified in Table 3-3 that could result in automatic act-uation of HPI was reviewed. In addition, the spurious actuation of HPI at power was considered. A qualitative evaluation of the NSS plant conditions which could evolve during extended operation of HP! following such events was performed. From this evaluation, the approximate range of surge flow rates and coolant temperatures into the pressurizer were identified. The evaluation results ior the 177- and 205-FA NSS units are given in section 4.

3-6

Section 4 TRANSIENTS/ACCIDENTS THAT CHALLENGE PORVs AND/OR PSVs 4.1 GENERAL Each transient/accident listed in Table 3-2 was reviewed as described in section 3.

Those transients/accidents found to result in the actuation of the PORVs and/or PSVs are covered in an event-by-event basis in this section.

4. 2 FSAR/RELOAD REPORT EVENT 4.2.1 Feedwater Malfunction/Decrease in Feedwater Temperature 4.2.1.l 177-FA NSS Units Event Description A decrease in feedwater (FW) temperature may result from the last FW heater stage being out of service or from the opening of the heater bypass valve that will bypass all the high-pressure feedwater heaters.

The NSS response is dependent on the severity of the FW temperature decrease. The analyses reviewed assume a FW temperature reduction of 85F due to a bypass of all high-pressure FW heaters. The FW system malfunction occurs at time zero .*

As the FW temperature decreases, the reactor coolant temperature decreases. This in turn causes an increase in reactor power for an end-of-core life condition. The reactor trips on high flux after approximately 30 seconds. The turbine stop valves then close, causing a sudden increase in steam pressure and its corresponding T t" sa The reactor inlet temperature will increase following T t of the steam generator, sa and thus, T will also increase. This results in an increase in RCS pressure to avg the PORV setpoint of 2255 psig, which is reached at 38 seconds. The PORV opens on steam and steam flows until the transient is turned arcund and RCS pressure starts to decrease after peaking at 40 seconds at a maximum pressurizer pressure of 2400 psia.

The PSV setpoint is never reached for this transient.

4-1

This event is itemized in Table A-1 and shown graphically in Figure A-1 of Appendix A. Initial conditions for this event are liste:d in Table 4-1 and Table 4-14 shows expected PORV inlet fluid conditions.

Table 4-1. Initial Conditions and Assumptions for Decrease in Feedwater Temperature Transients for 177-FA Plants Reactor power level 100%

Time-in-life End-of-life Offsite power Available throughout transient RCS flowrate Nominal Turbine trip At reactor trip Reactor trip on High flux 4.2.1.2 205-FA NSS Units Event Description A ~eduction in main FW temperature to the steam generators may result from any of the following:

Closure of the extraction steam block valve to a E!W heater (high level in that heater).

Opening of FW heater bypass valve.

Opening of low net positive suction head (NPSH) bypass line (to by-pass the low-pressure heaters).

For the loss of extraction flow to the FW heaters, the plant response will be an initial slight overheating of the RCS. The reduced FW temperature will next produce an overcooling of the reactor assuming that the integrated control system (ICS) can-not take corrective action to reduce the feedwater flow rate. The temperature de-crease in the RCS will cause the ICS to pull the control rods to increase core power, or power may increase without ICS action if the moderator coefficient is negative; thus a reactor trip on high neutron flux may occur. Otherwise, the reduction of '

steam generator outlet temperature (steam) may actuate the steam temperature protec-tion system (STPS) to trip the turbine. This will lead to a reactor trip on either a neutron flux/feedwater flow rate or high RCS pressure. Assuming no ICS action, the main steam safety valves and the essential control and initiation system (ECI) controlled atmospheric dump valves will control steam pressure and relieve steam to remove sensible and decay heat.

• 4-2

For this event both the PORV and PSVs are challenged to open on steam. This event is itemized in Table A-2 and shown graphically in Figure A-2 of Appendix A. Initial conditions are listed in Table 4-2 and Tables 4-15 and 4-16 give valve inlet fluid conditions expected for this event.

Table 4-2. Initial Conditions for Decrease in Feedwater Temperature Transients for 205-FA Plants Power level 102%

Time-in-life Beginning-of-life Offsite power Available throughout transient RC flow rate Nominal T Nominal avg RC pressure Nominal ICS }Jo actions provided PORV Operable

. 4.2.2 Feedwater Malfunction/Increased Feedwater Flow 4.2.2.1 177-FA NSS Units Event Description

• The analysis of the transient for the 177-FA plants did not result in RCS pressures

• reaching the PORV opening setpoint.

4.2.2.2 205-FA NSS Units Event Description An increase in FW flow will result in an increase in steam generator level. If the ICS takes no action to reduce the FW flow, the increased steam generator level will increase the heat removal rate of the primary system. If the RCS temperatw*e de-creases and the moderator coefficient is negative at end-of-life (EOL), then reactor power will increase and may nearly match the excessive rate of FW flow into both steam generators. At high power levels the STPS will trip the turbine, resulting in a reactor trip on either the flux/feedwater flow rate or high RCS pressure.. Follow-ing the reactor trip (on high RCS pressure), steam pressure will be controlled by the main steam safety valve and the modulating atmospheric dump valves since a fail-ure of the turbine bypass valves was assumed for this transient. RCS pressure in-creases to the PSV setpoint and the PSVs open, turning the RCS pressure excursion around.

4-3

This event is itemized in Table A-3 and shown qraphically in Figure A-3 of Appendix A. Initial conditions are listed in Table 4-3, and Tables 4-15 and 4-16 list ex- .

pected PORV and PSV inlet conditions.

Table 4-3. Initial Conditions for Increase in Feedwater Flow Transients for 205-FA Plants Power level 102%

Time-in-life EOL Offsite power Available throughout transient RC flow rate Nominal T

.avg Nominal RC pressure Nominal ICS No actions provided PORV Non-operable 4 *. 2.3 Pressure Regulator Malfunction -

Decreased Steam Flow 4 .*2. 3 .1 177-FA NSS Units Event Description A steam pressure regulator malfunction could result in a decrease in steam flow.

NSS plant response will be influenced by the suddenness of the reduction in steam flow and reactor moderator coefficient.

As steam flow decreases, heat rexroval by the secondary side is reduced and results in an increase in RCS temperature and, depending on moderator coefficient, an in-crease in core reactivity. RCS pressure will also rise as the average moderator temperature increases. The reactor will trip on high RCS pressure. This event is the least severe of all the overheating events analyzed and the resultant RCS pres-sure excursion would be bounded for all parameters by the other overheating events. '

The PSVs setpoint would not be reached. PORV inlet fluid conditions would be bounded by the other overheating transients.

4.2.3.2 205-FA NSS Units Event Description A reduction in steam flow exiting the steam generators may result from a closing of the turbine governor valves, which may be caused by any of the following:

4-4

Reduction of the demand siqnal for governor valve position resulting from instrumentation or control equipment failure.

Closure of the qovernor valves by the diqital electro-hydraulic

• (DEH) system.

Operator error with the DEH controls* in the manual mode.

A slow ramp closure of the turbine governor valves with no corrective action by the ICS eventually leads to an increase in steam pressure. The assumption was made that the turbine bypass valves were inoperable~ The higher steam pressure reduces the heat transfer by the steam qenerator and leads to an increase in RC temperature.

Due to the slowness of this transient, RCS pressure will be maintained near setpoint even though reactor outlet temperature steadily increases to the Thot setpoint for reactor trip. The reactor trips with a subsequent turbine trip. Conservatively, a loss of ac power to the RC pumps following the turbine trip was also assumed. Simi-lar to the results for the 177-FA plant, this event is the least severe of all the overheating events analyzed. The resultant RCS pressure excursion would be bounded by the other overheating events. The PSV setpoint would not be reached. PORV fluid inlet conditions would be bounded by other overheating events.

4.2.4 Loss of Load (Turbine Trip With Runback) 4.2.4.1 177-FA NSS Units Event Description

• Turbine trips are generally caused by problems within the station itself, especially the turbine-qenerator set (such as a turbine trip on low lubricating oil pressure).

Loss of electrical loads can result from faults within the unit generator or from

. grid frequency disturbances which cause the unit's main breakers to open and discon-nect the unit from the grid.

For this load rejection condition, the ICS provides automatic power runback to 15\

rated power. All electrical loads continue to receive power from the unit auxiliary substation. Feedwater is supplied by the turbine driven main feedwater pump.

As the electrical load is shed from time zero, the turbine-generator accelerates, causing the throttle valves to close. Closure of these valves will increase the secondary system pressure to the condenser dump, atmospheric dump, and main steam safety valve setpoint at approximately 1 second into the transient. Steam will be vented to the atmosphere for about three minutes until the condenser dump valves can handle all excess steam generation. The steam relief permits excess energy to be

• removed from the primary system to prevent a high RCS pressure trip and allow the RCS to stablize. The PORV setpoint of 2255 psig is reached at 10 seconds.

4-5 The PORV

opens on steam and steam flows for approximately 15 seconds, reclosing at 2205 psig.

The PSVs are not challenged.

This event is itemized in Table A-4 and shown graphically in Figure A-4 of Appendix A. Initial conditions are listed in Table 4-4 and Table 4-14 shows PORV inlet con-ditions.

Table 4-4. Initial Conditions for 177-FA Plants -

Loss of Load Transient Power level 100\

Time-in-life BOL Off site power External electrical load shed RC flow rate Nominal Turbine trip Due to load shed at time zero ICS On-line PORV Operable 177-FA Plant Differences After

..

• the initial few seconds,

. this transient will be different for Midland 1 and 2 than for the other 177-FA plants, since an electrical load rejection is only 60\ for this plant (the rest of the load is a process steam supply). The plant will run back to 40\ rated power and steam will be vented to the atmosphere until the con-denser dmnp valves can handle all the steam generated. The PORV is predicted to open on steam and passes steam. The PSV is not predicted to be challenged.

4.2.4.2 205-FA NSS Units Event Description For the 205-FA NSS units this event is bounded by the loss of condenser vacuum tran-sient.

4.2.5 Turbine Trip With Reactor Trip 4.2.5.1 177-FA Units Event Description Turbine trip producing reactor trip can be caused by any of the following:

Failure of the ICS system to produce a runback signal.

Failure of the condenser and atmospheric dump valves to open (with the ICS working properly).

4-6

Closure of the FW valves after the runback signal.

The reactor will trip on high RCS pressure or high flux for a runback signal failure.

The steam generators will remove decay heat by. rejecting steam to the turbine bypass system following a reactor trip. Main or emergency feedwater will be supplied to the steam generators.

For the turbine trip with FW valves closing, the reactor will also trip on high RCS pressure or temperature with steam rejection to the turbine bypass system.

The only steam relief for failure of the turbine bypass system and atmospheric dump valves is through the main steam safety valves. The reactor will attempt to run back to 15% full power, with all the main steam safety valves relieving excess steam. If the runback has been accomplished, some of the valves will close as the steam pres-sure decreases below the higher setpoints and the generated steam will be relieved by the remaining lower setpoint valves. Main or emergency feedwater will be supplied to the steam generators. During this event the RCS temperature and pressure increase due to decreased heat transfer in the steam generators. RCS pressures reach the PORV setpoint between 2 and 4 seconds into the transient. The PORV opens on steam and passes steam until the RCS pressure excursion is turned around *

• This event is itemized in Table A-5 and shown graphically in Figure A-5 of Appendix A. Initial conditions for this event are listed in Table 4-5 and Table 4-14 shows

"'PORV inlet fluid conditions. The PSVs are not challenged by this event.

Table 4-5. Initial Conditions for 177-FA Plants -

Turbine Trip/Reactor Trip Transients Power level 98%

Offsite power Available throughout transient RC flow rate 100%

Turbine trip Generator trip test PORV Operable

-Note: This information was taken from an actual turbine trip test transient at TMI-1, August 13, 1974 *

• 4-7

4.2.5.2 205-FA Units Event Description For the 205-FA units this event is bounded by the loss of condenser vacuum transient.

4.2.6 Closure of an MSIV at Full Power For the 177-FA units, the analyses do not predict RCS pressures high enough to chal-lenge the PORV or the PSVs.

For the 205-FA units, this event is bounded by the loss of condenser vacuum tran-sient.

4.2.7 Loss of Condenser Vacuum at Full Power 4.2.7.1 177-FA Units Event Description A loss of condenser vacuum at full power may result from any of the following:

Loss of circulating water pumps.

Gross air in-leakage to condenser.

Inadvertent opening of a vacuum breaker.

Loss of an air removal system (e.g., an air ejector).

,:High condenser pressure will initiate a turbine trip following the loss of *condenser

Vacuum.

• The ICS will begin to run the plant back, but the unavailability of the con-

.,denser dump system will lead to inadequate heat removal.

on high RCS pressure.

The reactor will then trip Since steam pressure and temperature in the steam generators will be higher than normal, the RC temperature will also be higher than normal.

RCS pressure response to this event is bounded by a turbine trip with runback. Ini-tial conditions for this event are listed in Table 4-6 and Table 4-14 gives PORV in-let fluid conditions. The PSVs are not challenged by this transient.

Table 4-6. Initial Conditions for 177-FA Plants - toss of Condenser Vacuum at Full Power Transients Power level 100%

Offsite power Available throughout transient RC flow rate No:rmal Turbine trip PORV ICS Prior to reactor trip Operable Operable 4-8

4.2.7.2 205-FA Units Event Description A loss of *condenser may be caused by any of the following:

• Failure of condenser vacuum pumps.

Gross air in-leakage to condenser.

L:>ss of condenser circulating water.

A slow decrease in condenser vacuum will cause a reduction in electrical generator output and the ICS will attempt to increase reactor power and steam flow to restore the generated megawatt output to the setpoint. For the purpose of analysis, the turbine is tripped manually at 110\ power to simulate a trip due to low condenser vacuum *.

The turbine bypass system and the atmospheric dump valves are assumed to fail to op-erate and steam pressure increases until the main steam safety valves open. This results in an increase in RCS temperature and pressure to the setpoint for tripping the reactor. The PORV and pressurizer spray valve are assumed not to operate. RCS

,,.pressure continues to increase until the PSVs open. After a few seconds, the PSVs

.**close and RC pressure returns to a near normal value.

• =~isI:::::li:o~:::~::: ~:rT~~: :::n:n:r:h~::t::a~:i:~~: ~=7F:::r:a:~: :~l:P~:::~

the expected PSV inlet fluid conditions. Table 4-15 lists the PORV inlet fluid con-

• '*di tions if the PORV were assumed to operate. This analysis, however, did not take

' --credit for the PORV.

Table 4~7. Initial Conditions for 205-FA Plants - Loss of Condenser Vacuum Transients Power level 102\

Time-in-life BOL Offsite power Available throughout transient RC flow rate Nominal T Nominal avg RC pressure Nominal ICS Only takes action to correct low megawatts PORV Non-operable 4-9

4.2.8 Loss of Offsite Power The analyses reviewed for the 177-FA plants do not predict RCS pressures high enough to challenge the PORV or PSVs.

4.2.8.1 205-FA Units EVent Description Loss of offsite power events are usually the result of a postulated event. Specif-ically, lightning can strike the main switchyard and knock out power to the plant.

There have been occurrences at operating plants in which the station had sUfficient warning and diesel generator sets were started before the loss of power.

After the loss of all ac power to the station, a time interval of 10 seconds has been assumed for the start of two emergency diesel generators, plus an additional time delay of 40 seconds to automatically load the operating diesel generators. In this interval the steam- and motor-driven emergency FW pumps will start. At the same time the ac power is lost the reactor and turbine are tripped, RC pumps lose power and start to coastdown, and the FW condensate pumps trip. The condenser cooling water pumps trip and the turbine bypass system is assumed to be unavailable for steam pres-sure control. The ECI-controlled modulating atmospheric dump and main steam safety valves are used to control steam pressure.

The increase in main steam pressure will reduce the heat transfer from the primary to*the secondary system and cause a momentary increase in RCS temperature and pres-sure. Since the reactor has already tripped, the increase will be very short lived.

The capacity of the modulating atmospheric dump valves is greater than the decay heat and the RCS is cooled down to a lower pressure and temperature than the normal oper-ating plant in less than one minute. The modulating atmospheric dump valves then maintain the steam pressure at a desired setpoint in order to hold RCS temperature and pressure at the desired values. The RCS pressure excursion does not reach PSV setpoint.

This event is itemized in Table A-7 and shown graphically in Figure A-7 in Appendix A. Initial condit~ons for this event are presented in Table 4-8 and Table 4-15 shows PORV inlet fluid conditions expected for this event.

4-10

Table 4-8. Initial conditions for 205-FA Plant -

Loss of Offsite Power 'l'ransient

• Power level Time-in-life Offsite power RC flow rate 102%

BOL Unavailable at time zero Flow coastdown starts at time zero T

avg Nominal RC pressure Nominal ICS No actions provided PORV Assumed inoperable 4.2.9 Control Rod Bank Withdrawal at Power 4.2.9.1 Generic Event Description A bank withdrawal at power is a moderate frequency event which may be due to a fail-

.ure in the integrated control system (ICS) or an operator error.

The plant response during a bank withdrawal at power will vary as a function of ini-tial conditions. FSAR analyses are performed at beginning-of-life (BOL) conditions

• • '-to maximize peak system pressure. A spectrum study is usually performed to determine

.'the variation of peak pressure due to changes in reactivity insertion rate, Doppler

.:-and moderator coefficients, and power level. Of these parameters, the most important are the reactivity insertion rate and power level. In all FSAR analyses, the PORV and pressurizer sprays are assumed inoperative.

For a bank withdrawal, reactor protection is provided by a high-pressure trip for small reactivity insertion rates and a high flux trip for large reactivity insertion rates. The highest system pressure and most limiting pressurizer valve inlet fluid conditions are obtained for the largest reactivity insertion rate that will result in a high-pressure trip. At full power for 205-FA plants, this corresponds to a reac-tivity insertion rate of about 2.4 x 10-s t.k/k-s, while for 177-FA plants, this

• 4-11

corresponds to a rate of 1.0 x 10- 5 llk/k-s. As power decreases the largest insertion rate, causing a high-pressure trip, increases; thus, it is expected that higher peak pressures will result at lower i.pitial power levels.

insertion rate of 4 x 10- 5 At low power conditions, an llk/k-s at 15% power. for 205-FA plants and 3 x 10-~ llk/k~s at 20% power for 177-FA plants were selected as representative accidents to determine limiting valve inlet conditions. These are conservative choices because these large reactivity insertion rates are possible only with the withdrawal of more than one rod bank. The simultaneous **withdrawal of multiple banks is less likely than a single bank withdrawal, especially considering the number of banks available for withdrawal when the plant is at power.

With the reactor initially at full power, a rod bank withdrawal results in a minor system pressure excursion. On the 205-FA plant with an insertion rate of 2.4 x 10- 5 llk/k-s, pressure increases over the first half minute until a reactor trip is reached. Because of the small insertion rate, low surge rates are experienced. The pressurizer pressure does not reach the assumed safety valve setpoint (2590 psia),

and thus no pressurizer relief is required for a bank withdrawal at full power. The response of a 177-FA plant for an insertion of 1.0 x 10- 5

~k/k-s is very similar.

Because of the lower insertion rate, the pressure increase is slower, increasing over the first minute. However, in all other respects, the same trends as the 205-FA plants are noted and no pressurizer relief is required.

With the reactor at low initial power levels (~15 to 20%), a reactivity insertion rate up to that equivalent to the withdrawal of the maxim\JlI\ worth, single rod bank does not result in a pressure excursion which requires pressurizer steam relief to limit the event consequences. If more than one bank of rods is ass\JlI\ed to be with-drawn simultaneously, the pressurizer safety valves are required if the PORV and pressurizer sprays are assumed inoperative (standard assumption). For the 205-FA plants with a reactivity insertion rate of 4 x lo- 5 llk/k-s at 15% power, system pres-sures increase over the first 15 seconds until the reactor trips on high pressure and reactor power is reduced. The ass\JlI\ed pressurizer safety valve set pressure (2590 psia) is reached, but no significant overshoot in pressurizer pressure above the lift pressure is predicted. The response for the 177-FA plants is similar. Rod bank withdrawals at lower power levels than considered here would be bounded by the startup accident from a system pressure standpoint.

Initial conditions are listed in Table 4-9. This event is itemized in Tables A-8 and A-9 and shown graphically in Figures A-8 and A-9 for 177-FA units, and Tables A-10 and A-11 and Figures A-10 and A-11 for the 205-FA units. Only steam relief is 4-12

~pected for this transient. The PSVs will be challenged only for high reactivity insertion rates at low power (15 to 20%). Typical PORV inlet conditions for this transient are given in Table 4-14 and 4-15~ Tables 4-16 and 4-17 give typical PSV inlet conditions.

Table 4-9. Initial Conditions for Bank Withdrawal Resulting in Limiting System Pressure Conditions Power level Low power Time-in-life BOL Reactivity insertion rate Highest insertion rate at a given power level that results in a high-pressure trip as opposed to a high flux trip.

PORV Inoperative

• -~4. 2 .1 O Control Rod Bank Withdrawal at Startup 4.2.10.1 Generic Event Description A rod bank withdrawal from a subcritical condition (startup accident) is a moderate

.frequency event which may be due to a failure in the ICS or an operator error.

The plant response during a bank withdrawal at startup will vary as a function of initial conditions. FSAR analyses are performed at BOL conditions to maximize the peak system pressure. A spectrum study is usually performed to determine the varia-tion of peak pressure due to changes in reactivity insertion rate and Doppler and moderator coefficients. Of these, the most important study is reactivity insertion rates. For all FSAR analyses, the PORV and pressurizer spray are assumed to be in-operable for this event.

For a small reactivity insertion rate, the reactor protection system (RPS) will trip the reactor on high RCS pressure. For a large reactivity insertion rate, the RPS will trip the reactor on high flux (177-FA plants) or high flux to reactor vessel temperature difference (flux - ~T trip) on the 205-FA plants. The highest system pressure and limiting valve inlet conditions result for the largest reactivity in-sertion rate that will still cause a high-pressure trip. High flux or flux - ~T trips occur earlier than high-pressure trips and this will result in lower peak sys-tem pressure. A typical reactivity insertion rate that will give the highest pres-sure for a 205-FA plant is 9.6 x 10- 5 ~/k~s. For this insertion rate, system 4-13

pressure will remain constant for the first minute into the transient. Then, a large pressure rise will be experienced when the reactivity addition is large enough to produce a significant rise in power. The plant trips on high pressure with the safety valves opening shortly thereafter. Pressurizer pressure will overshoot the PSV lift setpoint because the surge rate will exceed the safety valve capacity.

Pressure will decrease as the reactor trip takes affect and reduces core power. For a 177-FA plant, the system response is similar, but a slightly larger reactivity in-sertion rate (2.0 x 10-~ ~/k-s) leads to limiting pressure conditions.

Initial conditions are listed in Table 4-10. This event is itemized in Table A-12 and shown graphically in Figure A-12 for 177-FA units and in Table A-13 and Figure A-13 for the 205-FA units. Typical PORV inlet conditions for this event are given in Tables 4-14 and 4-15; Tables 4-16 and 4-17 present typical PSV inlet conditions.

Only steam relief out of the valves is predicted for this accident.

Table 4-10. Initiating Conditions That Result in Limiting Pressure Excursions Power level Time-in-life Reactivity insertion rate Hot zero power (HZP)

Beginning-of-life (BOL)

Largest that will pro-duce a high RCS pres-sure trip.

PORV Inoperative 4.2.11 Control Rod Ejection Accident 4.2.11.1 Generic Event Description The rod ejection accident is a limiting fault assumed to be caused by the physical failure of a pressure boundary component in the control rod drive (CRD) assembly.

Such a failure could cause a pressure differential to act on a control rod assembly and rapidly eject the assembly from the core region.

The rod ejection accident results in rapid increase in reactivity. The resulting power and system pressure excursion, however, are limited by the Doppler effect and terminated by the RPS trips. These trips may be high flux (177 and 205), high pres-sure (177 and 205) or high flux-to-reactor vessel temperature difference (205 plant only) depending on the reactor power level and reactivity insertion rate. Following 4-14

reactor trip, insertion of control rods beqins, and the power and pressure excursion are terminated within a few seconds

• The most limitinq initial conditions from a pressure excursion standpoint occur at

• BOL. With the reactor at power, the ejection of a control rod (with a worth at or below Technical Specification limits) results in a minor RCS pressure excursion.

For these conditions, a reactor trip occurs on high flux within the first few tenths of a second, and the RCS pressure is controlled without pressurizer safety or relief valve operation. At low or hot zero power (HZP) initial conditions, the system pressure excursion is much more severe. Usinq past FSAR analysis techniques, which do not take credit for the loss of reactor coolant out of the pressure boundary, pressurizer spray or PORV operation, this limiting fault imposes very severe bound-ary conditions on the PSVs. Based on a review of available analysis, representative valve inlet conditions at both hot full power (HFP) and ~ZP conditions are provided in Table 4-11. Overall, the assumptions inherent in these analyses are considered very conservative. The resulting predictions of system performance are provided in Tables A-14 through A-16 and Figures A-14 through A-16 for the 177-FA units and Tables A-17 through A-19 and Figures A-17 through A-19 for the 205-FA units. Less severe results would be expected at HZP conditions if the loss of reactor coolant from the pressure boundary or a more detailed model of the core's reactivity feed-back mechanisms were considered *

.Typical valve inlet conditions for this event are given in Tables 4-14 through 4-17.

Only steam relief is expected for this transient.

4-15

Table 4-11. Pressurizer Safety Valve Inlet Conditions for Rod Ejection Accident Generic rod ejection conditions(a) 177-FA J2lants 205-FA J2lants HFP HZP HFP HZP Maximum pressurizer pressurization rate, psi/s 80 175 130 171 Maximum pressurizer pressure, psia 2395(b) 2677 (b) 2541 (b,c) 2624(d)

Valve inlet fluid state Steam Steam Steam Steam (a)Limitirig pressure condition occurs at BOL-HZP with the ejection of the maximum rod worth allowed by the Technical Specifications.

(b)Based on an assumed valve lift setpoint of 2590 psia.

(c)Analysis did not take credit for the PORV or PSVs.

(d)Based on a valve lift setpoint of 2590 psia. Pressures approxi-mately 40 psi above the lift pressures are predicted at nominal lift pressures, i.e., 2500 psig.

4.2.12 4.2.12.1 Loss of Main Feedwater Generic Event Description i A loss of main feedwater (LOFW) is a moderate frequency event that can result from an abnormal closure of the main FW isolation or control valves or by a trip of the main FW pumps.

The plant response during a LOFW can vary depending on the initial conditions examined and assumptions made regarding equipment operation. Limiting system pressure condi-tions occur, however, with the reactor at full power with BOL core conditions, mini-mum steam generator water inventories (unfouled conditions), and a turbine trip at reactor trip. For the limiting conditions above, a LOFW results in gradual mismatch in energy production in the core and energy removal by the steam generators. The initial steam generator water level is boiled off and prima~ system pressure in-creases as the reactor coolant heats up and expands into the pressurizer. RCS pres-sure continues to increase until the core power has dropped to reduce the surge flow into the pressurizer. Long-term energy removal is assured through actuation of the auxiliary FW system which provides a backup source of feed.water to the steam gen-erators when main feedwater has been lost.

4-16

~ The severity of this moderate frequency event depends on the time the reactor is tripped. For both the B&W 177- and 205-FA plants, a reactor trip can occur as result of High RCS pressure.

An anticipatory trip (i.e., one that will occur prior to high RCS pressure) such as a trip of both main FW pumps or a high reactor flux to main feedwater flow ratio.

For the 177-FA plants, the anticipatory trips are generally control grade, whereas the high RCS pressure trip is included in the plant's reactor protection system (RPS) and is therefore safety-grade. On the 205-FA plants, both reactor trips are part of the RPS. Plant ,responses with reactor trip initiated by each of the parameters above have been considered in determining the approximate valve inlet conditions. A se-vere but not bounding high-pressure trip was considered for the 205-FA plants since an anticipatory.reactor trip will limit the severity of this event by normal RPS ac-tion.

'"With an anticipatory reactor trip, reactor scram occurs during the first few seconds of the transient. Because of the subsequent turbine trip, RC temperature and pres-sure increase so that the PORV will open and maximum pressure conditions occur within

• 4 to 8 seconds into the transient. With an anticipatory reactor trip, pressurizer pressure does not reach the PSV lift setpoint for either the 177- or 205-FA plants.

With a reactor trip on high RCS pressure, reactor scram will occur much later (14-18 seconds). The resulting RCS pressure excursion will be more severe compared to the system response with an anticipatory trip because less water will exist within the steam generator at the time of reactor trip. Under these conditions, pressurizer pressure would overshoot the safety valve lift setpoint and subsequently decrease when the safety valve relief capacity exceeds the surge rate into the pressurizer.

Initial conditions for a LOFW are listed in Table 4-12. This generic event is item-ized in Tables A-20 and A-21 and Figures A-20 and A-21 for the 177-FA units and in Tables A-22 and A-23 and Figures A-22 and A-23 for the 205-FA units. Typical PORV inlet conditions for this event are given in Tables 4-14 and 4-15; Tables 4-16 and 4-17 present typical PSV inlet conditions. Only steam relief is expected for this event.

4-17

Table 4-12. Initial Conditions 'l'hat Result in Limiting Rcs*pressure Conditions*for LOFW Power level 102% of rated power Steam generator inventory Min"imum Time-in-life BOL Offsite power Available throughout transient RC flow rate Nominal Turbine trip At reactor trip Reactor trip High RCS pressure 4.2.13 Feedwater Line Break 4.2.13.1 Generic Event Description A feedwater line break (FWLB) is a postulated design basis accident. For this event, lin.1-iting system pressure conditions occur from rated power with BOL core conditions, minimum steam generator water inventories (i.e., unfouled conditions), and with a turbine trip and loss of offsite power at reactor trip. The plant-response to a FWLB is similar to that of a LOFW.

may blowdown through the break.

The major distinction is that the steam generators RCS pressures increase rapidly causing the PSVs to open and the reactor to trip on high RCS pressure. RCS pressure increases until the power has decreased enough to reduce the surge flow into the pressurizer. Pressur-izer pressure overshoots the safety valve setpoint and only reduces to the setpoint when the safety valve relief capacity exceeds the volumetric insurge from the loops.

For a severe FWLB on B&W plants, RCS pressure peaks during the first 20 seconds of the accident and then decreases to a value at or below the PSV lift setpoint. During this pressure excursion period, only steam is relieved by the PSVs and/or PORV to maintain RCS pressures at acceptable levels. Because a FWLB can not only cause a loss of feedwater flow to the steam generator but also result in loss of initial steam generator(s) water inventory, the reactor coolant experiences. a large tempera-ture increase. Using FSAR assumptions that (1) maximize core power and loss of main feedwater from one or both steam generators and (2) minimize the availability of aux- '

iliary feedwater (e.g., by the postulation of a single active failure and loss of offsite power), the increase in RC temperature can result in the pressurizer filling and water relief out the PORV and/or PSVs. The potential for water relief is also 4-18

enhanced since the HPI system can be actuated during a FWLB. For both the 177- and 205-FA plants, the relief capacity of the pressurizer valves is sufficient to main-tain pressurizer pressure at or near the pressurizer valves lift setpoint under water relief conditions. Water relief will continue until auxiliary FW heat removal matches decay heat production and operator action is taken to secure HPI flow.

Representative plant response characteristics for the 177-FA units are given in Tables A-24 and A-25 and Figures A-24 and A-25 of Appendix Ai and for the 205-FA units in Table A-26 and Figure A-26. Initial conditions are listed in Table 4-13.

Based on these generic analyses results, representative valve inlet conditions for this accident when steam relief occurs are given in Table 4-14 through 4-17. Bound-ing valve inlet conditions under water relief conditions for a FWLB are given in section 4.4.

Table 4-13. FWLB - Initial Conditions That Result in Limiting Pressure Conditions Break location Inside containment downstream of feedwater check valves Power level 102% of rated power Steam generator inventory Minimum Time-in-life BOL Offsite power Lost at time of reactor trip RC flow rate Nominal Turbine trip At time of reactor trip Reactor trip High RCS pressure

• 4-19

Table 4-14. PORV Inlet Condition Resulting From FSAR/Reload Events for 177-FA Plants Event FW malfunction, decrease in FW temperature Assumed relief valve opening setpoints, psig 2240 Possible fluid state on opening Steam Predicted max.

pzr press.

psig 2385 Loss of load turbine trip with runback 2240 Steam 2335 Turbine trip with reactor trip 2240 Steam 2242 Loss of condenser vacuum 2240* Steam 2330 Rod bank withdrawal from 20%

full power 2240(a) Steam 253g(b)

Rod bank withdrawal at start-up 2240 (a) Steam 2515(b)

Rod ejection at HZl? 2240 (a) Steam 2662 (b)

LOFW with anticipating reac-tor trip 2255 Steam 2281 LOFW with high RCS pressure trip 2240(a) Steam 2519(b)

FW line break 2240(a) Steam 2591(b)

(a)PORV was assumed not to operate in the event analyses.

(b)These values are based on PSVs lifting at setpoints per Table 4-17.

4-20

Table 4-15. PORV Inlet Conditions Resultinq From FSAR/Reload Events for 205-FA Plants Assumed relief Possible Predicted max.

valve openinq fluid state prz press.

Event setpoints, Psiq on opening psiq FW malfunction, decrease in FW temperature 2295 Steam 2615 FW malfunction increase in FW flow 2295 Steam 2525 Loss of condenser vacuum 2295 (a) Steam 255S(b)

Loss ~f offsite ac 2295 Steam 2279 Rod bank withdrawal from 15%

full power 2295 (a) Steam 2580(b)

Rod bank withdrawal at start-up 2295 (a) Steam 2595(b)

Rod ejection at HZP 2295 (a) Ste&u 2615(b)

LOFW with anticipatinq reactor trip 2295 Steam 2301 LOFW with high RCS pressure trip 2295 (c) . Steam 2503 FW line break 2295 (a) Steam 2577(b)

(a)PORV was assumed not to operate in the event analyses.

(b)These values are based on PSVs lifting at setpoints per Table 4-16.

(c)PORV was assumed to operate in this event analyses *

• 4-21

Table 4-16. Safety Valve Inlet Conditions Resulting From FSAR/Reload Events for 205-FA Plants Assumed SV Possible Max. pzr Maximum Minimum opening fluid state pressure, pressurization pressurization Event setpoints, psig on opening psig rate, psi/s rate, psi/s FW malfunction, decrease in FW temperature 2500 Steam 2615 70 Approaches zero FW malfunction, increase in FW flow 2500 Steam 2525 77 Approaches zero Loss of condenser vacuum 2500 Steam 2555 70 Approaches zero Rod bank withdrawal from 15%

FP 2575 Steam 2580 85 Approaches zero Rod bank withdrawal at startup 2575 Steam 2595 100 Approaches zero Rod ejection at HZP 2575 Steam 2609 171 Approaches zero I

l\.J l\.J LOFW with high-pressure trip 2500(a) Steam 2503 60 Approaches zero FW line break 2500 Steam(b) 2577 75 Approaches zero (a)PORV assumed operative.

(b) p oss ibl e t rans1t1on

. . to sub-cooled water (see Table, 5 - 3)

• Table 4-17.

• Safety Valve Inlet Conditions Resulting From FSAR/Reload Events for 177-FA Plants Assumed sv Possible Max. pzr Maximum Minimum opening fluid state pressure, pressurization pressurization Event setpoint, psig on opening psig rate, rsi/s rate, psi/s Rod bank withdrawal from 20%

FP 2575 Steam 2539 55 Approaches zero Rod bank withdrawal at startup 2500 Steam 2515 95 Approaches zero Rod ejection at HZP 2575 Steam 2662 175 Approaches zero LOFW with high RCS pressure trip 2500 Steam 2519 81 Approaches zero FW line break 2545 Steam(a) 2591 115 Approaches zero

....I N

w (a)Possible transition to subcooled water (see Table 5-2).

4.3 COLD PRESSURIZATION TRANSIENTS The PORV is used for protection of the reactor vessel during cold overpressurization transients for B&W 177-FA NSS only.

by-unit basis, the following:

The following sections provide, on an NSS unit-A description of the design basis, i.e., equipment utilized and de-sign transients/accidents, for low temperature overpressure protec-tion.

A sununary of the expected PORV inlet conditions for the event that requires the highest relief rate, including the approximate duration each fluid state would exist at the valve inlet, ranges of surge rates into the pressurizer, and subcooling of the liquid flowing into the pressurizer.

4.3.1 Description of Design Basis for Cold Overpressure Protection Systems 4.3.1.1 General Each plant utilizes a low temperature overpressure protection system to protect the reactor vessel from overpressurization at low temperatures. The basic criteria for

• this system is that no single active component failure will result in reactor ves-sel overpressurization (operator action can be utilized at 10 minutes as a backup to a single active component failure).

The basic overpressure protection system used in 177-FA plants consists of the PORV with a low-pressure setpoint. In the event of a PORV failure, credit is taken for operator action to terminate the pressurization event at 10 minutes into the event.

This provides two redundant and diverse means of overpressure protection. The steam or gas space in the pressurizer will generally provide a time period of 10 minutes or more during a pressurization event before the pressure would reach the setpoint of the PORV. The reactor coolant system (RCS) always operates with a steam or gas space in the pressurizer; no operations involve a "solid water" condition, other than a system hydrotest. Those 177-FA plants that use tr.e PORV in the low-tempera-ture overpressure protection system are identified in Table 4-18.

In the development of the low-temperature overpressure protection system, the fol-lowing potential pressurizing events were examined:

Erroneous actuation of the high-pressure injection (HPI) system- For most plants, this event is prevented by a requirement to rack-out the circuit breakers for the motors of the closed HPI valves at low RC system temperatures.

4-24

Makeup control valve (makeup to the RCS) fails full open - For most plants, this event requires the highest relief rate through the PORV.

Restrictions on maximum pressurizer water level provide 10 minutes or more for operator action to terminat~ this event. Operator action is not required if PORV functions properly.

Erroneous opening of the core flood tank discharge valve - This event is prevented by closing the valve and racking-out the valve motor cir-cuit breaker during plant cooldown before RCS pressure is decreased below 600 psig. Analysis also has shown that even if one core flood tank discharged, the equilibrium pressure reached (at the end of the discharge) is significantly less than the PORV setpoint.

Erroneous addition of nitrogen to the pressurizer - This event is prevented by a regulator and a relief valve in the nitrogen addition lines.

Thermal expansion of reactor coolant after starting an RC pump due to stored thermal energy in the steam generator - This event is self-terminating with the resultant RCS pressure below the PORV setpoint.

The event terminates when thermal equilibrium is reached between the steam generator secondary side and the RCS

• All pressurizer heaters erroneously energized - This is a very slow pressure transient, it takes approximately 50 minutes to reach the PORV setpoint. The event produces' a low rate of steam production in the pressurizer.

Temporary loss of the decay heat removal system's capability to re-move decay heat from the RCS - This also is a very slow pressure transient, it takes approximately 30 minutes to reach the PORV set-point. This event produces an insurge rate into the pressurizer which is about 50% of the rate produced by the makeup control valve failing full open.

For those plants which utilize the PORV in the overpressure protection system, Table 4-19 lists the PORV setpoint, the RCS temperature below whic~ the PORV is used, and the pressurizer insurge rates for the pressurization events which potentially could increase pressure to the PORV setpoint.

4-25

Table 4-18. Utilization of p0RV in Low Temperature overpressure Protection PORV used in low-temperature overpressure Plant protection 177-FA Oconee 1, 2, 3 Yes

'l'MI-1, 2 Yes Crystal River 3 Yes AN0-1 Yes Rancho Se co Yes Midland 1, 2 Yes Davis-Besse No

-*'..t Table 4-19. Required Relief Rates for pORV TMI-1; AN0-1; Oconee Crystal Rancho 1, 2, 3 TMI-2 River 3 Se co Midland 1 and 2 RCS temp. below which PORV is used, F 250 275 280 280 330(a) ~280 PORV setpoint, open/close, psig 550/500 500/450 550/500 550/500 550/500 360/310

1. Pressurizer heaters erroneously ener-gized,(b) lb/h steam 7555 7440 7555 7555 7555 7100

2. Loss of decay heat re-moval capability Insurge rate to pressurizer, gpm 120 120 120 120 140 120 Required PORV re-lief rate, lb/h steam 1175 1070 1175 1175 1370 780

3. Makeup control valve failed full open Insurge rate to pressurizer, gpm 245 245 260 360 255 275 4-26

Table 4-19. (Cont'd)

TMI-1; AN0-1;

• Required PORV re-lief rate, lb/h steam Oconee 1, 2, 3 2400 TMI-2 2190 Crystal River 3 2550 Rancho Se co 3530 Midland 1 and 2 2500 1780 steam; steam; 360 wa- 275 wa-ter (c) ter<c)

4. One HPI train erro-neously actuated rnsurge rate to pressurizer, gpm NA NA NA NA 535 560 Required PORV re-lief rate, lb/h steam NA (d) NA NA 5240 3630 stea:i<c) 560 gpm water Cc ,e)

(a)In RCS temperature ranges of 330 to 280F.

(b)Based on 100\ of heater capacity generating steam from saturated water in pres-surizer.

(c)Not concurrent; steam relief could be followed by water relief.

(q)TMI-2 must rack-out the circuit breakers for the motors of the four closed HPI valves below 275F RCS temperature to preclude a PORV relief requirement for this transient.

(e)The PORV is not required to relieve this flow rate at the PORV setpoint. The maximum allowable pressure is significantly higher than 1000 psig; therefore, the pressure can be allowed to increase to 1000 psig. At 1000 psig, the surge rate into the pressurizer is 475 gpm *

• 4-27

4.3.1.2 Plant Specific Design Basis 4.3.1.2.1 Oconee Units 1, 2, and 3; TMI Units 1 and 2; Crystal River 3, and AN0-1 Plants These plants use the basic cold overpressure syst~ described in the preceding sec-tions, consisting of the PORV with a low-pressure setpoint which is backed up by op-erator action at 10 minutes to terminate the event. The pressurization events, as described, are applicable to these plants.

4.3.1.2.2 Rancho Seco Plant This plant is different from the ones described in the preceding general description paragraphs in two aspects. The makeup control valve has a much higher flow rate capacity than the other plants. For the event of the makeup control valve failing full open, the increasinq pressure will reach the PORV setpoint in less than 10 min-utes (~7 minutes). Because the design criteria requires that the overpressure pro-tection system be designed for a single active component failure (the PORV fails to open) and less than 10 minutes are available for operator action to terminate the pressurization event, an interlock was added that will automatically shut off (de-energize) all three makeup pump motors at an RCS pressure of 550 psig. The overpres-sure protection system for the Rancho Seco plant thus consists of: (1) the PORV with an open setpoint of 550 psig RCS pressure, (2) the interlock which automatically shuts off all three makeup pumps at 550 psig RCS pressure, and (3) operator action, as a backup to these two automated functions, at 10 minutes into the pressurization event.

4.3.1.2.3 Midland Unit 1 and 2 Plants These plants are different from the ones described above in several respects.

Cold overpressure protection is provided in the 280 to 330F RCS temperature range by the PORV, with a setpoint of 550 psig. The PORV is backea up by operator action to terminate the pressurization event. Appropriate restrictions on maximum pressurizer water level in this RCS temperature range ensure that there is 10 minutes available before the increasing pressure exceeds the allowable pressure limit for the event producing the fastest rate of pressure increase. Only one of the two HPI trains is racked-out in this RCS temperature range. Thus, the event of erroneous actuation of one HPI train produces the fastest rate of RCS pressure increase and also places the highest relief capacity demand on the PORV.

~

4-28

Overpressure protection is provided below 280F RCS temperature by: (1) the PORV with a setpoint of 360 psig, and (2) the decay heat removal system (DHRS). The DHRS

.~rop line isolation valves are always open below 280F RCS temperature so that there

• is a flow path between the DHRS drop line relief valve and the RCS. The DHRS drop line relief valve has a capacity of 1815 gpm which is sufficient to terminate the pressure increase for any of the events. Both HPI trains are racked-out below 260F RCS temperature.

4.3.2 Expected PORV Inlet Fluid Conditions The event, on a per plant basis, which requires the highest relief rate by the PORV is tabulated in Table 4-20. In addition, Table 4-20 provides expected valve inlet and pressurizer parameters *

• -- ~-29

Table 4-20. Swnmary of Expected PORV Inlet Conditions for the Cold Overpressurization Event Requiring Maximum Relief Rate Minimum time Pressurizer Surge rate into from event PORV open Fluid state at liquid pressurizer at initiation to setpoint, valve inlet temperature PORV setpoint, fill pressurizer Plant Event psig during relief range, F gpm of water solid, min.

Oconee Makeup control 550 Sat. steam @ 338-457 245 >10 1, 2, 3; valve fails (500 for 565 psia (515 (338-453 (100-250F) (b)

TMI-1,-2 full open (a) TMI-2) for TMI-2) for TMI-2)

AN0-1, Makeup control 550 Sat. steam @ 338-460 260 Crystal valve fails 565 psia (449 for (100-280F) >10 River 3 full open AN0-1)

Rancho Makeup control 550 Sat. steam @ 338-449 360 <10 Se co valve fails 565 psia fol- (100-280F) full open lowed by pres-surizer liquid(c) w 0

I Makeup control 360 Sat. steam @ 338-417 275 >10 valve fails 375 psia (100-280F) full open One HPI train 360 Sat. steam @ 415-426 560 <10 Midland erroneously 375 psia fol- (260-280F) (e) 1 I 2 actuated lowed by pres-surizer liquid(d)

One HPI train 550 Sat. steam @ 415-458 535 >10 erroneously 565 psia (280-330F) actuated (a)TMI-2 must rack-out the circuit breakers for the motors of the four closed HPI valves below 275F RCS temperature for the makeup control valve failing open event to be the event requiring the maximum relief rate.

(b)

For TMI 245 gpm of water (100 to 275F).

I

• Table 4-20. (Cont'd)

(c)Duration of steam relief is ~so seconds followed by ~40 to 120 seconds of water relief. The 40 seconds corre-sponds to depletion of the water in the makeup tank which is the water source. The 120 seconds corresponds to 10 minutes after the event initiation, assuming a different water source for the makeup pump was being used (such as the BWST).

(d)Duration of steam relief is ~3.6 minutes followed by ~1.9 minutes of water relief at which time 10 minutes has passed and operator action is asswned to terminate the event.

(e)The PORV is not required to relieve this volumetric flow rate at the PORV setpoint. The maximum allowable pres-sure is significantly higher than 1000 psigi therefore, the pressure can be allowed to increase to 1000 psig, the surge rate into the pressurizer is 475 gpm.

4.4 EXTENDED HPI INJECTION EVENTS 4.4.1 General Each transient/accident identified in Table 3-3 that was predicted to result in ac-tuation of the HPI system and a spurious actuation at power were reviewed as fol-lows:

A qualitative evaluation of the plant conditions which could evolve during extended HPI operation was performed.

Based on this evaluation it was determined that the steam line break and feedwater line break would yield bounding results for HPI-related insurge transients.

For each of the B&W NSS types (177-FA raised and lowered loops and 205-FA) the approximate range of pressurizer surge rates and system temperatures were calculated assuming that HPI is allowed to operate at full capacity. The results are given in Tables 4-21 and 4-22.

4.4.2 Qualitative Evaluation of Plant Conditions To support the EPRI valve testing program, an attempt was made to provide surge flow rate and RC system temperature data which would bracket expected conditions. To achieve this goal, FSAR analyses using conservative assumptions that result in ex-pected maximum surge flow rates and system temperature swings were reviewed. From this review of RC system dynamics for those transients identified in Table 3-3 (based on existing generic analyses), it was concluded that the SLB and FWLB should provide bounding conditions. The SLB should have the minimum system coolant temper-ature and should evolve to a condition where the primary system was recovering (heating up) from a low temperature condition due to decay heat production. The FWLB, however, may have the maximum system coolant temperatures as well as the greatest potential for system heatup rate due to the mismatch between decay heat and secondary heat removal at the time of pressurizer fill. The other transients are bounded because (1) the FSAR steam generator tube rupture (SGTR) accident and a LOCA provide primary system break which tends to reduce mass flow through a safety valve, (2) the pressure regulator malfunction is really a small SLB with less severe temperature drop, and (3) in the case of spurious HPI actuation the boron addition causes a power reduction that results in a net system contraction reducing surge flow caused by HPI flow.

An estimate of the surge flow rate and system temperature for the bounding SLB and FWLB accidents was made. The system temperature used is the most extreme temperature 4-32

expected at the onset of pressurizer fill based on existing SLB and EWLB transients (see Tables 4-21 and 4-22). The surge flow rate was calculated by adding these components:

1. The flow from all three HPI pumps. See Table 4-23 for these values.

2. The system expansion rate as detennined by a review of existing tran-sient analyses. An estimate was made of when the pressurizer would fill with liquid. Then the core heat addition rate was compared with the heat removal rate due to auxiliary feedwater flow (AFW). In the case of the SLB, it was assumed that no AFW was flowing (i.e., the sys-tem was allowed to heatup at a maximum rate). Decay heat was assumed to be 1.2 times ANS 5.1 values. The mismatch between core heat addi-tion and heat removal was then used to estimate the system expansion rate due to system heatup.

This approach is conservative and results in extremely high pressurizer insurge rates. First, only two HPI pumps would be expected to be automatically actuated.

Second, the use of 1.2 times ANS S.i decay heat and minimum secondary heat removal provides a conservative prediction of system expansion due to the heatup of reactor coolant. In addition, the system conditions are based on accident analyses which

• used very conservative FSAR type assumptions; this leads to extremes in both sys-tem temperature and surge flow rates.

follows:

1.

Two examples of these conservatisms are as The 400F minimum temperature, based on SLB accident conditions, is con-servatively low. If less conservative assumptions were used (e.g.,

credit for steam generator level control) , a temperature greater than 450F would be expected.

2. For the FWLB, it has been assumed that the initial inventory from both steam generators can be lost out the break up to the time the main FW isolation valves close. For this to occur, flow restrictions (i.e.,

check valves) must be ignored. This assumption leads to (a) an early fill of the pressurizer when the core heat generation rate is high and Cb) extremely high pressurizer insurge rates.

4.4.3 Results For each B&~l type, the pressurizer insurge rates due to HPI addition alone and to HPI addition in combination with the maximum possible system expansion due to heatup of the reactor coolant have been calculated. For these calculations, a range of RC temperatures was addressed from a system heatup and expansion standpoint. The low 4-33

temperature range was addressed using SLB assumptions, and the high temperature range was based on FWLB assumptions. The temperature at which the transition from SLB to FWLB assumptions was made is the maximum hot leg temperature which would be.

expected during (post-trip) natural circulation conditions. Surge rates are pro-vided at pressure conditions corresponding to the PORV and PSV lift setpoints.

These results are provided in Tables 4-21 and 4-22.

For the 177-FA raised loop plant, it is seen that due to the low head HPI pumps, the only component of surge flow is that due to system expansion. The lowered loop 177-FA plants have a substantially higher surge flow rate since the HPI pumps can deliver flow at pressures in excess of the PORV and pressurizer safety valve set-points. Finally, the 205-FA plants have the largest surge flow rates due to in-creased HPI flow and system expansion rates. For the 177-FA lowered loop plants and the 205-FA plants, it was found that the PORV can accommodate the resulting pressurizer insurge due to HPI; however, when system heatup and HPI are considered simultaneously, the resulting pressurizer insurge rates can exceed the PORV relief capacity.

A bounding range of pressurization rates were calculated which would be applicable to all 177- and 205-FA plants. The maximum pressurization rate proved to be that experienced on the 205-FA plants. This maximum pressurization rate was calculated to be 63 psi/second, and is the result of the maximum uncontrolled HPI flow and maximum heatup rate as previously described. To determine a minimum flow it can be hypothesized that HPI flow was throttled back to nearly zero with an extremely low heatup rate. Under these conditions, the pressurization rate could approach zero.

Therefore, a bounding pressurization rate range for the pressurizer valves would be defined as 0-65 psi/second.

4-34

Table 4-21. Evaluation of HPI Induced Refill for 177-FA Plant Surge flow due to Surge flow due to HPI and sy:i?tem HPI only, lbrn/min. heatup, lbm/min.

Pressurizer pressure, At At At At At At psia Accident 400F 602F 640F(c) 400F 602F 640F(c) 177-FA Plants, Lowered Loop 2465 SLB 4725 3760 6980 (a) 2515 SLB 4510 3590 6805 6,555 2465 FWLB 3760 3425 (b) (b) 2515 FWLB 3590 3275 10,400 11, 520 177-FA Plants, Raised Loop 2465 SLB 0 0 3300 6,715 2515 SLB 0 0 3295 6,680 2465 FWLB 0 0 5,465 7,075 2515 FWLB 0 0 5,435 7,005 (a)Up to the time of pressurizer fill, the steam relief capacity of the PORV can maintain pressurizer pressure below the PSV lift pressure.

When water relief starts, pressurizer pressure would increase to the PSV lift setpoint. Surge flow would correspond to the values at the safety valve lift setpoint.

(b)Surge flow exceeds the PORV capacity when HPI and system heatup are considered. Valve inlet conditions would be those specified at the PSV lift setpoint of 2515 psia.

(c)640F is the highest anticipated hot leg temperature. Without any thennal mixing the coolant at the inlet of the pressurizer valves could be as high as 650F, which is the normal pressurizer fluid temperature.

4-35

Table 4-22. Evaluation of HPI Induced Refill for 205-FA Plants Pressurizer pressure, psi a Accident Surge flow du~ to HPI onl~, lbm/min.

At 400F ~

At At

.§2.91:

Surge flow due to 400F HPI and system heatuEE lbm/min.

622F 650F 2310 SLB 7555 5725 10,410 (a) 2515 SLB 6545 4990 9,610 8890 2310 FWLB 5725 5240 (a) (a) 2515 FWLB 4990 4600 8500 8330 (a)Up to the time of pressurizer fill, the steam relief capacity of the PORV can maintain pressurizer pressure below the PSV lift pressure.

When water relief starts, pressurizer pressure would increase to the PSV lift pressure.

Table 4-23. HPI Flow (Three Pumps)

Plant type At pressurizer safety valve lift pressure, gEm At PORV lift pressure, gpm 177-FA raised loop 0 0 177-FA lowered loop 620 650 205-FA plants 900 1040 4-36

• Section 5 FLUID CONDITIONS AT PSV INLET Table 5-1 gives the fluid conditions expected at the PSV inlet as a result of FSAR/

reload type event analyses. (It should be noted that it was assumed that the PORV was inoperable in establishing these conditions.) This table covers B&W 177- and 205-FA units. Tables 5-2 and 5-3 give the results of the analyses of extended operation of the HPI system after an FSAR event that actuates HPI, or a spurious actuation of the HPI system when the reactor is at power. The results assume the PORV does not function. As discussed earlier, the PSVs are not challenged by cold overpressurization events.

Table 5-1. Bounding Safety Valve Inlet Cbnditions Resulting From FSAR/Reload Events for 177- and 205-FA Plants Assumed PSV Maximum Pressurization opening Possible pressurizer rate, J2Si/S setpoints, fluid state pressure, Limiting events psig on opening psig Max Min 177-FA Plants Rod ejection at 2575 Steam 2662 175 NA HZP 205-FA Plants Rod ejection at 2575 Stearn 2609 171 NA HZP NA: Not applicable.

• 5-1

Table 5-2. Bounding Safety Valve Inlet Conditions Resulting From Extended Operation of HPI for 177-FA Plants Surge line flow when PSV Assumed PSV Maximum Max./min.

is passing liquid, lb/min.

opening Possible pressurizer pressurizer setpoints, fluid state pressure, liquid temp. , At At At Limiting events psig on openingCa) psig F 400F 602F 640F 177-FA Plants (Excluding DB)

Steam line break 2500 Steam 2500 602/400 6805 6,555 NA FW line break 2500 Steam 2500 640/602(b) NA 10,400 11,520 Davis-Besse Steam line break 2500 Steam 2500 602/400 3295 6,680 NA FW line break 2500 Steam 2500 640/602(b) NA 5,435 7,005 U1 I

N (a) Initial opening of valve will be on steam. Subsequent openings could possible be on subcooled liquid.

(b)Without thermal mixing of the surge line liquid with the 650F liquid normally in the pressurizer, the pressurizer safety valves could open on 650F liquid.

Table 5-3. Bounding Safety Valve Inlet Conditions Resulting From Extended Operation of HPI for 205-FA Plants Surge line flow when PSV Assumed PSV Maximum Max./min.

is passing liquid, lb/min.

opening Possible pressurizer pressurizer setpoints, fluid state pressure, liquid temp. , At At At Limiting events psig on opening(a) psig F 400F 622F 650F Steam line break 2500 Steam 2500 622/400 9610 8,890 NA FW line break 2500 Steam 2500 650/622 NA 8,500 8,330 (a) Initial opening of valve will be on steam. Subsequent openings could possibly be on subcooled liquid .

• section 6 FLUID CONDITIONS AT PORV INLET As discussed in section 3 of this report, the FSAR analyses reviewed did not neces-sarily assume that the PORV was operable. As a matter of record, most of the anal-yses assumed that the PORV was inoperable. No credit was taken for the PORV because

• the PORV uses control grade signals. However, if a transient/accident is in pro-gress and the PORV is not de-energized or valved out, it can be expected to operate.

Therefore, the limiting conditions that the PORV could possibly see would in fact be conservatively enveloped by the same peak pressurizer pressures and fluid state as the PSVs.

Table 6-1 presents possible PORV inlet conditions drawn from FSAR analyses that were performed using the PORV operability assumptions discussed above. It should be noted that since the TMI-2 accident the PORV set point for the 177-FA plants was raised to 2450 psig and the RCS high-pressure trip set point was lowered to 2300 psig. These

• modifications were mandated by the NRC in an attempt to reduce the number of chal-lenges to the PORV and PSVs. The raising of the PORV set point has little effect on FSAR analyses results since credit for these valves is generally not taken. The lowering of the RCS high-pressure reactor trip set point has the effect of reducing the severity of FSAR overpressurization events. Therefore, the PORV/PSV inlet fluid conditions presented (which are based on standard FSAR assumptions) are more limit-ing than those that would be expected if these changes were considered explicitly.

Table 6-2 gives the results of the extended operation analyses of the HPI system after the FSAR event that actuates the HPI, or a spurious HPI initiation at power.

Table 6-3 defines the fluid conditions at the PORV inlet that are expected to exist when the PORV is functioning as a RCS cold overpressure protection device.

6-1

Table 6-1. Bounding PORV Inlet Conditions Resulting From FSAR/Reload Events for 177- and 205-FA Plants Limiting events 177-FA Plants Possible fluid state on opening Max. pzr pressure, psig Max./min.

liquid temp.

at valve inlet

• Rod ejection at HZP Steam 2662 NA 205-FA Plants Rod ejection at HZP Steam 2609 NA NA: Not applicable 6-2

Table 6-2. Bounding PORV Inlet Conditions Resulting From Extended HPI Operation Following FSAR/Reload Events for 177- and 205-FA Plants Max. Min.

Assumed liquid liquid relief valve temp. at temp. at opening Possible Max. pzr valve valve setpoints, fluid state pressure, inlet, inlet, Limiting events psig on opening(a) psig F F 177-FA Plants (Excludin2 DB-1)

Steam line break 2450 Steam 2500(b) 602 400.

FW line break(c) 2450 Steam 2500(c) 64o<d> 602 Davis-Besse Plant Steam line break 2450 Steam 2500(b) 602 400 FW line break 2450 Steam 2500(c) 64o<d> 602 205-FA Plants Steam line break 2295 Steam 2500(b) 622 400 FW l'1ne b re ak (c) 2295 Steam 2500(c) 650 622

• (a) Initial opening on steam with possible transition to subcooled water.

sequent openings possibly on subcooled liquid.

(b)Up to the time of pressurizer fill, the steam relief capacity of the PORV Sub-can maintain pressurizer pressure below the PSV lift pressure. When water relief starts, pressurizer pressure would increase to PSV lift setpoint.

(c)Surge flow exceeds the PORV capacity when HPI and system heatup are considered.

Valve inlet conditions would be those specified at the PSV lift setpoint of 2500 psig.

(d)Without thermal mixing of the surge line liquid with the 650F liquid normally in the pressurizer the PORV could open on 650F liqu~d.

6-3

Table 6-3. PORV Inlet Conditions Resulting From Cold Pressurization Events for 177-FA Plants Plant Opening/

closing setpoints, psig Limiting pressurization event Possible fluid state

~at valve inlet Max. pzr pressure, psig Max.

liquid temp. at valve inlet, F

Min.

liquid temp. at valve inlet, F

Oconee 1,2,3; 550/500 Makeup control sat. steam 550 NA NA TMI-1, Jl.N0-1, valve fails @ 565 psia CR-3, TMI-2 full open Rancho Seco 550/500 Makeup control Sat. steam ( ) 550 449 338 valve fails @ 565 psia a full open Midland 1,2 550/500 One HPI train Sat *. steam 550 NA NA erroneously @ 565 psia actuated 360/310 One HPI train Sat. steam(b) 360 426 415 erroneously @ 375 psia actuated 360/310 Makeup control Sat. steam 360 NA NA valve fails @ 375 psia full open (a)Duration of steam relief is ~so seconds followed by ~40 to 120 seconds of water relief. The 40 seconds corresponds to depletion of the water in the makeup tank which is the water source. The 120 seconds corresponds to 10 minutes after the event initiation, assuming a different water source for the makeup pump was being used, such as the BWST.

(b) Duration

. o f s t eam re l'ie f is

. ~ 3

• 6 minutes

. f o 11owed b y ~1

• 9 minu

. t es o f water re-lief at which time 10 minutes has passed and operator action is assumed to terminate the event.

6-4

• Section 7 REFERENCES

1. TMI-2 Lessons Learned - Task Force Status Report and Short-Term Recommendations, NUREG-0578, Nuclear Regulatory Commission, July 1979.

2. Clarification of TMI Action Plan Requirements, NUREG-0737, United States Nuclear Regulatory Commission, November 1980.

3. Program Plan for the Performance Testing of PWR Safety and Relief Valves, Rev 1, Electric Power Research Institute, July 1, 1980

• 7-1

APPENDIX A

• Graphic Event Descriptions A-1

This appendix contains detailed ~raphic descriptions of selected FSAR/reload tran-sients/accidents. A tabulated sequence of events and figures showing pertinent pressurizer parameters are included for each event.

Table A-1. Sequence of Events for Decrease in Feedwater Temperature Transients for 177-FA Plants Event Time, s Feedwater malfunction occurs 0.0 High flux setpoint exceeded 29.5 Control rods begin to drop 29.9 Peak neutron power occurs 30.0 Minimum DNBR occurs 30.0 Peak system pressure occurs 40.0 A-2

1400 1200 2500 1000 PRESSURE 800 u 2400 ID en t'll:I

• -en 600 c:L 400

=

e ID - 2300 -

SURGE FLOI 200 ID t:IA

I en en  ::::I cu

,_ 0 In a.. 2200 N

-200 a..

2100 -400 2050 -600 0 5 10 15 20 25 30 Time, sec 235 230 LEVEL 225 610 220 en cu 215

.c u

= 210 600 .....

cu -

tU 205 ,_

cu 590 ....ca

I 200 ,_

,_ cu tU 195 c:L ecu N

,_ TEMPERATURE 580 ....

I 190 tlO

"'cu en 185 cu

..... ....a a.. 570 1BO :c 175 170 560 165 0 5 10 15 20 25 30 Time, sec Figure A-1. Selected Pressurizer Parameters for Decrease in Feedwater Temperature Transient for 177-FA Plants A-3

Table A-2. Sequence of Events for Decrease in Feedwater Temperature Transient for 205-FA Plants Item Time, s Steam extraction flow terminated 0 Feedwater with reduced temperature enters the steam generators 37 Control rods withdraw due to low T 55-105 avg STPS trips main turbine 115 Steam safety valves open 116 Modulating atmospheric dump valves open 119 Reactor trip on high RC pressure 120.5 Pressurizer safety valves open 121 Pressurizer safety valves close 125.5 Main steam safety valves close 170 A-4

.; 1500 SURGE FLOI 1000 (.)

2800 ID en ca =

• -en 500 CL 2600 ID -

c LI..

I en 0 ID en 2400 t:IG ID a..

=

en a::

a::

..... -500 .....

a..

IL. 2200 PRESSURE 2000 -1000 110 114 118 122 126 130 134 138 Time, sec 640 260 en TEMPERATURE ID LI..

(.)

c 630 -

ID 240 .....

=

ca ID .....

ID 220 620 ID CL

-J e

..... ID I-ID N

... 200 610 -J t:IG ID

I

"'"'cu ....c

..... :c a.. 180 600 110 114 118 122 126 130 134 138 Time, sec Figure A-2. Selected Pressurizer Parameters for Decrease in Feedwater Temperature Transient for 205-FA Plants A-5

Table A-3. Sequence of Events for Increase in Feedwater Flow for 205-FA Plant Item Time, s Main feedwater control values*open and MFW pump speeds increase to high speed stop 0 Turbine tripped by STPS 22.5 Main steam safety valves open 24 Reactor tripped on high RC pressure 29.5 Pressurizer safety valves open 30.5 Pressurizer safety valves close 33 Main steam safety valves close 55 A-6

1600

• ca en a.

m 2600 2400 PRESSURE BOO 0

u ID

.c:i 0

LI..

I ID en

-BOO ....

tall en SURGE FLOI

....m 2200  ::I Cl.. ""

a: m N N Cl..

2000 -1600 *::

I en en

....m Cl..

1800 -2400 20 25 30 35 40 45 50 55 Time, sec en 260 650 m

.c LI..

u

= 630 ....

m m

220

....ca

I cu cu

....m

,_ lBO 610 e::::i.

cu

...,cu I-

.... tlll

I en 140 590 _,cu en cu TEMPERATURE ....

.... 0 Cl..

100 570 20 25 30 35 40 45 50 55 Time, sec Figure A-3. Selected Pressurizer Parameters for Increase in Feedwater Flow Transient for 205-FA Plants A-7

Table A-4. Sequence of Events for Loss of Load Transient for 177-FA Plants Event Loss of external load Manual control a.a Time, s Automatic control a.a Initiation of steam relief from turbine bypass valves and steam safety valves 2 1 Peak system pressure occurs 15 15 Steam .safety valves close 10a 18a.

Reactor power reduced to 15% rated power 24a 24a A-8

2300 500 400 300 u

ca SURGE.FLOI 200 enIU ut 100 ce

=. 2200 IU

- 0 -

I en

....ca CD en -100 a::

IU D-

-200 0 a::

D- 2100 -300 bO cu PRESSURE ....

""=

-400

-500

-600 2000 -700 0 20 40 60 80 100 i20 i40 250 en cu

.c: 240 u

c cu 230 630 cu

....cu HOT LEG ......

220 620

....cu-N TEMP

=

en ....=

610 ....

en ' ca cu

.... 210 IU D- =.

ecu

~

200 600 t:IO cu 0

190 590 :c 0 20 40 60 BO 100 120 140 Time, sec Figure A-4. Selected Pressurizer Parameters for Loss of Load With Reactor Runback Event for 177-FA Plants A-9

Table A-5. Sequence of Events for Turbine Trip/Reactor Trip Transient for 177-FA Plants Item Turbine tripped-initiated by signal from turbine shutdown system Turbine stop valves closed Time, s a.a 1.a Steam pressure increases to setpoint for opening turbine bypass system valves 1.a Steam pressure increases to setpoint for opening steam safety valves 3.a Press'lirizer spray valve and PORV open 2.a-4.a Feedwater flow reaches a minimum due to high steam generator pressure 4.a RC temperature and pressure increase due to higher steam generator pressure 4.a Reactor tripped on high RC pressure (with spray valve and PORV active) s.a RC system temperatures increase to peak values due to reduced heat transfer of both steam generators 12.a Pressurizer PORV and spray valve closed 12.0 Steam safety valves closed (assuming turbine bypass system val~es are oper-able) 30.0 A-la

800 2400 SURGE 400 FLOI ~

ID t:IO en en PRESSURE 0 .c

I.

ID

I en 2200

~

Q en 2000 -400

....ID a..

ID

....tlol

I

.... Cl')

. 800 ....

N a..

1800 N a..

1600 -1200 1400 0 10 20 30 40 50 60 70 Time, sec

• 250 200 620 ID

> 600 -

-....ID-ID

....ID 150

I ca N ....ID

.... 580  ::I.

I TEMPERATURE eID en en 100 ....

....ID a..

t:IO 50 ________________________________________,540 560

~

Q

z::

0 10 20 30 40 50. 60 70 Time, seconds Figure A-5. Selected Pressurizer Parameters for Turbine Trip With Reactor Trip Transient for 177-FA Plants A-11

Table A-6. Sequence of Events for Loss of Condenser Vacuum Transient* for 205-FA Plants Item Loss of vacuum causing turbine* gover-nor valves to open Maximum reactor power reached Time, s o.o 92 Turbine tripped (manually simulated low condenser vacuum trip of turbine) 92 Reactor tripped on high RC pressure 101 Pressurizer code safety valves open 102 Pressurizer code safety valves close 105 A-12

1600

• 2600 800 PRESSURE u cu Ill ca ..........

Cl Ill

=. 2400 0 CU*

Q

I Ill Ill 2200 - BOO L&..

Q)

Cl..

Q)

....bO

....  :::I N

Cl.. 2000 -1600 ""'....

SURGE FLOI N Cl..

1BOO *2400 90 95 100 105 110 115 120 125 260 ] 630 Ill Q)

.c:

LEVEL c..J L&..

c:

220 620 -

Q)

I cu cu

....I 1BO 610

....ca Q) a.

....cu E N ._

Q)

.... bO

I 140 TEMPERATURE 600 Q)

Ill ....I Ill

!U Cl..

Q

z:

100 590 90 95 100 105 110 115 120 125 Time, sec Figure A-6. Selected Pressurizer Parameters for Loss of Condenser Vacuum at Full Power Transient for 205-FA Plants A-13

Table A-7. Sequence of Events for Loss of Offsite Power for 2aS-FA Plants Item Time, s Loss of all non-emergency a-c power a.a RC pumps power lost a.a Condenser cooling water pumps power lost a.a Condensate pumps are tripped a.a Reactor is tripped i.a Turbine is tripped i.a Modulating atmospheric dump valves and steam safety valves open 4.0 Peak RC pressure is reached (PORV is not assumed to open and pres-surizer safety valves do not open) 5.0 Emergency diesel generators started 10.0 All auxiliary feedwater pumps oper-ating 40.0 Loading sequence on emergency diesels completed {plant in quasi-steady-state condition) so.a A-14

2400 1400 Col cu e"'

cu ..........

2300 ....till

I

.c ca c:

"'=- PZR SURGE FLOI Q

....:::I 2200 CD 0 CD

....:::Itill CD a.. ""....

cu CD

....:::IbO ....N 2100. PZR PRESSURE ...."':::I "':::I Q

CD a..

2000 -4000 0 10 20 30 40 50 60 240 560 c:

CD .....

CD 220 640

_,I CD CD N

....:::Ica

I 200 Hot Leg Temperature 620 CD c.

"'cu eCD

.... I-a.. till CD

'C _,I

....ca 12)

+J Col 180 600 Q

'C c: Indicated Pzr Level 160 580 0 10 20 30 40 50 60 Time, sec Figure A-7. Selected Pressurizer Parameters for Loss of Offsite Power at Full Power Transient for 205-FA Plants A-15

Table A-8. Sequence of Events for Rod Bank Withdrawal From Full Power (177-FA Plants)

Event Bank withdrawal equivalent to reactiv-ity insertion rate of 1.0 x ia-s t.k/k-s begins Time, s a.a High pressure trip setpoint reached 57.3 Rod starts to drop 58.0 Pressurizer safety valve lift pressure reached (2515 psia) N/A Peak RCS pressure reached 59.6 A-16

2600 u

ca PRESSURIZER ID

"'E

"' 2400 Cl.

PRESSURE 200 '.c:::i ID

=

"'"' 2200 100 0

ID ID Q..

....ao 2000 0 =

c.')

0 30 40 50 60 70 Time, sec 620

- PRESSURIZER ID

> 25 LEVEL 610 ID I.I..

'Cl ID

=

er

_, 24 =

600 ....

ca ID ID Q.

N E

.... 23 HOT LEG 590 .....

ID

= TEMPERATURE

"'cu Ill

.... 580 Q.. 22 0 30 40 50 60 70 Time, sec Figure A-8. System Response for Rod Bank Withdrawal at HFP Accident for 177-FA Plants A-17

Table A-9. Sequence of Events for Rod Bank Withdrawal From Low Power (177-FA Plants)

Event Bank withdrawal equivalent to reac-tivity insertion rate of 3 x 10-~

~/k-s begins Time, s o.o High pressure trip setpoint reached 13.7 Rods begin to drop 14.4 Pressurizer safety valve lift pres-sure reached (2515 psia; valves assumed not to lift) 16.7 Peak RCS pressure reached 18.5 A-18

2600 . - - - - - - - - - - - - - - - - - - - - - - - .

2500 ca PRESSURIZER

• -en 2400 PRESSURE 600 c..l Q. cu

. 500 en c

....:::s cu en 400 .

en 2300 311 Cb cu 300 ...

Cl SURGE FLOW 200 cu

....:::sti.II 2200 100 ""

2100 0 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 Time, sec

-.... 25 PRESSURIZER LEVEL 24 600

....cu N

.... 23 590

s en en cu

.... 22 580 Cl..

0 2 4 6 B 10 12 14 16 18 20 22 24 26 28 30 Time, sec Figure A-9. System Response for Rod Bank Withdrawal From Low Power (~20%) Accident for 177-FA Plants

• A-19

Table A-10. Sequence of Events for Rod Bank Withdrawal From Rated Power (205-FA Plants)

Event Time, s Bank withdrawal equivalent to reac-tivity insertion rate of 2.4 x io-s o.o Afc/k-s initiated High RCS pressure trip setpoint reached 39.7 Rods start to drop 40.3 Pressurizer valves open N/A Peak RCS pressure reached 43.0 A-20

2600 2500 800 u

cu

.~ 2400 SURGE FLOI 400 en en CL =

cu

i en 2300 0 0 en CD ID a...

PRESSURIZER ....t:IO 2200 -400  :::i PRESSURE U) cu N

-800 :::i 2100 en en CD a...

2000 -1200 0 10 20 30 40 50 60 Time, sec 22 640 20 630 t:IO CD CD 0

cu

..... 620

....cu 18 ....cu N

i

.... ca

i en 16 610 cu CL en ecu cu a... I-14 600 0 10 20 30 40 50 60 Time, sec Figure A-10. System Response for Rod Bank Withdrawal Accident at HFP Accident for 205-FA Plants

• A-21

Table A-11. .. Sequence of Events for Rod Bank Withdrawal From 15% Power (205-FA Plants)

Event Bank withdrawal equivalent to reactiv-ity insertion rate of 4 x 10-~ ~/k-s inititated High RCS pressure trip setpoint reached Time, s o.o 13.7 Rods start to drop 14.3 Pressurizer valves open 15.1 Peak RCS pressure reached (2655 psia) 15.9 A-22

2700 2000

• ca 2600 2500 PRESSURIZER PRESSURE 1800 1600 1400 c;i

~

Cl

"'a. 1200 0

a:

> 2400 1000 .....

en CD

(;)

....... 800 tlO a: SURGE FLOI  ::l

~ en 2300 600 ....

IU 400 N

l 2200 200 "'en IU o ~

2100 -200 0 5 10 15 20 25 30 35 Time, sec 24 640 22 630 t:IO

> HOT LEG _.

IU TEMPERATURE ....

620 0

a:

20  ::

N a:

....::l IU en .....

en

....... 18 610 ....ca a: IU

~ a.

eIU 600 ......

16 0 5 10 15 20 25 30 35 Time, sec Figure A-11. System Response for Rod Bank Withdrawal From Low Power (15%) Accident for 205-FA Plants A-23

Table A... 12 *. Sequence of Events for Rod Bank Withdrawal at Startup Accident (177-FA Plants)

Event Time, s Rod bank withdrawal~ reactivity insertion rate of 2.2 x 1a-~

~k/k-s beqins a.a High pressure reactor trip set-point reached 35.6 Rods begin to drop 36.3 Safety valves open at 2515 psia 38.5 System pressure peaks and starts to decrease 38o5 A-24

2700

• ca

• ~

2600 2500 PRESSURIZER 1600 u

CD en

- PRESSURE 1200 .cl CD

I

!S

2400 Q CD a.. BOO u...

cu

....ti.a 2300  :::I 400 CD N

2200 ....

I en en 0 ....CD 2100 ,,. I ii.

J 0 20 25 30 35 40 45 50 Time, sec

-.... 28 u...

560

• cu cu

'C

I C'

26 24 PRESSURIZER LEVEL 550 --

ti.a cu Q

CD

.... 540 .... :::I cu N

SURGE FLOW ....ca

....:::I 22 CD Q.

en e CD en

....cu 530 I-a..

20 20 25 30 35 40 45 50 Time, sec Figure A-12. System Response for Rod Bank Withdrawal at Startup Accident for 177-FA Plants A-25

Table A-13. Sequence of Events for Rod Bank Withdrawal at Startup Accident (205-FA Plants)

Event Reactivity insertion of 9.6 llk/k-s initiated x io- 5 High RCS pressure trip setpoint reached Time, s o.o 69.25 Rods start to drop 69.9 Pressurizer safety valves open at 2590 psia 70.7 Peak RCS pressure reached 71.9 Pressurizer safety valves close 77 .1 A-26

2700 2200 SAFETY 2650 VALVES 2000 u cu OPEN en 2600 1800 ' c IQ

• Cl

• -en 2550 1600 ......

a.

cu t:l!3 CD ....

I 2500 1400  :::I en en ""....

cu

.... PZR N cu A..

2450 SURGE 1200 ....

I FLOW en en 2400 1000 ....

cu A..

\.. PZR PRESSURE 2350 800 2300 600 0 50 60 70 80 90 100 24 23 PZR LEVEL 600 cu 22 SURGE LINE TEMP 0 all

> 21 580 cu cu

....cu N

I 20 19 Cl cu 560 ....

"'cu"'

I IQ A.. 18 cu Cl.

e cu 17 540 .....

0 10 20 30 40 50 60 70 80 90 100 Time, sec Figure A-13. System Response for Rod Bank Withdrawal at Startup Accident for 205-FA Plants A-27

Table A-14. Sequence of Events for Rod Ejection From HFP (177-FA Plants)

Event Time, s Rod ejected a.a High flux trip setpoint reached a.a25 Control rods begin to drop a.425 Peak RCS pressure reached 3.9oa A-28

• A-29 Table A-15. Sequence of Events for Rod Ejection From HZP With Reactor Trip on High RCS Pressure (177-FA Plants)

Rod ejection Event High pressure reactor trip setpoint reached Time, s o.o 3.48 Control rods begin to drop 4.18 Pressurizer safety valves open at 2590 psia 6.3 Peak RCS pressure reached 6.3 A-30

2800 1400 1200 c.1 2700 ID en l'a .........

• -=. 1000 Cl en 2600 2500 BOD Q m

=en 2400 600 ID en m

.... ....1:111 CL 2300 PRESSURIZER 400 =

2200 PRESSURE 200 2100 0 D 2 3 4 5 6 7 B 9 10 Time, sec 570 HOT LEG ID

> TEMPERATURE '"" 560 ID 27 ....

IU 550 ...

'Cl

=

=

a- 26 ~

....... ID 25 =.

e 540 .....

ID ID N

24

=

Ill en 23

....cu 22 530 a..

0 2 3 4 5 6 7 a 9 10 Time, sec Figure A-15. System Response for Rod Ejection at BOL-HZP With High Pressure Reactor Trip Accident for 177-FA Plants A-31

Table A-16. Sequence of Events for Rod Ejection From HZP With Reactor Trip on High Flux (177-FA Plants)

Rod ejection Event High flux reactor trip setpoint reached Time, s a.a a.185 Control rods begin to drop a.585 Pressurizer safety valves open at 2590 psia 3.5 Peak RCS pressure reached 5.3 A-32

3000 .2000 SURGE FLOW 2900 1BOO 2800 1600 u IU Ill 2700

• -=

1400 Cl Ill Q.

2600 1200 .-

- a

.... 2500 1000 .-.....

IU

=

Ill IU Ill IU 2400 800 .... tlO a..

2300 PRESSURIZER 600 ""

=

2200 PRESSURE 400 2100 200 2000 0

~ 4 5 6 7 8 0

Time, sec IU 28 HOT LEG TEMPERATURE 590 ......

IU IU 27

'Cl

....=

=

~ *25 570 ~

IU Q.

.... 25 E IU N

IU

.... 24 550 tlO

=

en en 23 PRESSURIZER LEVEL _,

IU IU a.. 22 0 2 3 4 5 6 7 8 Time, sec Figure A-16. System Response for Rod Ejection at BOL-HZP With High Flux Trip of Reactor Accident for 177-FA Plants A-33

Table A-17. Sequence of Events for Rod Ejection at HFP-BOL (2a5-FA Plants)

Rod ejected Event High flux trip setpoint reached Time, s a.a 0.015 Control rods begin to drop 0.415 Pressurizer safety valves open Peak RCS pressure reached 3.95a A-34

2600 1700 1500

• =

2500 2400 PZR SURGE 1300 1100 900 700 u

ID Cl Q,

....- 2300 Cl ID 500 .....

=in en 300 ....

a:i

~

ID PZR PRESS =

"- 2200 100 "" ....ID N

-100 ....

=

2100 -300 en in ID

-500 "-

2000 -700 0 1 2 3 4 ~

Time, sec 20 650

~

ID

....a 19 640

-=....

Cl CD ID 18 630 ID

....a =

~

ID N

i.

"- eII>

17 620 ID

~

16 610

=

0 2 3 4 5 Time, sec Figure A-17. System-Response for Rod Ejection at BOL-HFP Accident for 205-FA Plants A-35

Table A-18. Sequence of Events for Rod Ejection From HZP-BOL (205-FA Plants)

Rod ejection Event High flux reactor trip setpoint reached Time, s o.o 0.138 Control rods begin to drop 0.538 Pressurizer safety valves open at 2590 psia 3.46 Peak system pressure 4 2800 2700 2800 ca 2600 2400 ucu

• - 2500 2000 =

"'c::a.

cu

- 2400 1600 *-

Q

=

"' 2300 1200 .....

"'....cu cu t:IG a.. 2200 800 ....

2100 PRESSURIZER ~ =

PRESSURE 400 2000 0 0 2 3 4 Time, sec 22

~

cu 21 580 cu PRESSURIZER LEVEL .....

= cu-

= 20 570 ....

=-

_, =

~

ca

....cu ....

cu c::a.

N 19 560 ecu

"'"'=

cu 18

.... 550 a..

0 2 3 4 Figure A-18.

Ti me, sec System Response for Rod Ejection at BOL-HZP Accident for 205-FA Plants A-36

Table A-19. Sequence of Events for Rod Ejection From BOL-HLP (205-FA Plants)

Event Ti.me, s Rod ejection 0 High flux reactor trip setpoint reached 0.115 Control rods begin to drop o. 515 Pressurizer safety valves open at 2540 psia 2.88 Peak system pressure reached 3.2 A-37

2800 3200 2700 2800 u

~

• -en 2600 2400 ID en a.

2500 2000 a

ID

= 2400 1600 *Q en en .....

.... 2300 CD 1200 ID

~

....t:IG 2200 PRESSURIZER 800 =

en 2100 PRESSURE 400 2000 0 0 2 3 4 5 6 Time, sec

.... 22

--- PRESSURIZER CD cu 21 LEVEL 630

~

= 620 cu-

I er 20 ....

610 ....

I

~

600 ....

~

cu cu N HOT LEG a.

ecu

I 19 TEMP 590 t-en en 580 CD

~

18 570 0 2 3 4 5 6 Time, sec Figure A-19. System Response for Rod Ejection at BOL-HLP Accident for 205-FA Plant A-38

Table A-20. Sequence of Events for I.OFW on 177-FA Plants With Reactor Trip on High RCS Pressure Event Time, s Loss of feedwater initiated 0.0 Flow to SGs terminated 5.0 Low level in SG reached 14.0 RCS high pressure setpoint reached 14.2 Rods start to drop 14.6 Turbine tripped 14.7 (a ,b)

Pressurizer safety valves open 16.0 AFW initiated 41.0 SGs dry 78.0 (a)No credit was taken for PORV or pressurizer spray operation.

(b)

Code safety valve lift and reseat was assumed at pressurizer pressures of 2515 and 2514 psia, re-spectively *

• A-39

2800 ,.

2700 m

• -"' 2600 1200 Q CD Q.

2500 PRESSURIZER 1000 '.Cl "'

ID 2400 PRESSURE

=

800 *=

CD 2300 600 .....

Q.,

CD 2200 400 ...

0.0 2100

=

200 2000 0 0 2 4 6 8 10 12 14 16 18 20 22 24 26 Time, sec

.... 28

--- 27 SURGE TEMPERATURE 614 CD CD 26 612 D

'C 25 610 ....=

=

a' 24 608 IQ

..... CD a.

CD 23 606 e

CD N

=

22 604 CD 0.0 CD 21 PZR LEVEL 602 =

Q.,

20 600 0 2 4 6 8 10 12 14 16 18 20 22 24 26 Time, sec Figure A-20. System Response for LOFW With Reactor Trip on High RCS Pressure Accident for 177-FA Plants A-40

Table A-21. Sequence of Events for LOFW on 177-FA Plants With Anticipatory Reactor Trip Event Time, s Loss of feedwater initiated 0.0 Flow SGs terminated 5.0 PORV opens(a,b) 7.0 (c)

Flux/flow trip setpoint reached 2.0 Rods start to drop 4.0 Turbine trip 4.5 AFW initiated 69.0 (a)Credit for the PORV was taken with opening ahd closing setpoints of 2270 and 2269 psia, re-spectively.

(b)With an anticipatory trip no pressurizer safety valve operation occurred.

(c)Loss of offsite power with subsequent RC pump coastdown was assumed coincident with reactor trip

• A-41

2350 700 ,.

600 2300 500 co

• -ena. 400 uCD CD - 2250 PRESSURIZER 300 ~ "'

..... PRESSURE

=

en 200 0*

"'CD

~ 2200 100 ....

CD t:loG 0 .....

s 2150 -100 "'

-200 2100 -300 0 5 10 15 20 Time, sec 606 SURGE TEMPERATURE 604 4-1 CD CD

~

23 22 PRESSURIZER LEVEL 602 600 e CD

s co CD Q.

CD N .....

CD

..... CD t:loG

s .....

"' 21 598  :::s CD

~

20 596 0 5 10 15 20 Time, sec Figure A-21. System Response for LOFW With Anticipatory Reactor Trip.'Accident for 177-FA Plants A-42

Table A-22. Sequence of Events for LOFW on 205-FA Plants With Reactor Trip on High Pressure

• Flow to SGs terminated PORV opens (a)

Event Loss of feedwater initiated Time, s 0.0.

5.0 12.0 RCS high pressure trip setpoint reached 18.0 Rods start to drop 18.4 Turbine trip 18.5 Initial pressurizer safety valves opening(b) 20.0 AFW initiated 35.0 (a)PORV operation was assumed with opening and closing pressure setpoints of 2310 and 2285 psia, respec-tively.

(b) .

Pressurizer sa f ety valve lift at 2515 psia~ blowdown was not modeled

• A-43

2700 .~

1800 2600 1600

~

PRESSURIZER u cu

• -Cll PRESSURE 1400 Cll Q. c 2500

....cu-1200

~

1000 Cl*

Ill Ill .....

....cu 2400 a.

800 t::IO cu 600 ~

2300 ""'

400 SURGE FLOI 200 2200 0 0 5 10 15 20 25 JD 35 40 Time, sec 27 26 633 631 ....cu-cu

> 25 cu

~

.... 24

-....cu ....cu

~

~

23 TEMP 629 eQ.

.... cu cu N

22 ~

cu

~ 21 627 ....

ti.a

~

Cll

~

Ill

...cu a.

20 19 625 18 17 623 0 5 10 15 20 25 30 35 40 Time, sec Figure A-22. System Response for LOFW With Reactor Trip on High RCS Pressure Accident for 205-FA Plants A-44

-Table A-23. Sequence of Events for LOFW on 205-FA()

Plants With Anticipatory Reactor Trip a

• Event Loss of feedwater initiated*

Reactor trip on flux to MFW flow Rods begin to drop Time, s o

2.5 2.9 Turbine trip/LOOP 3.0 Flow to SG terminated .5.0 PORV opens (2310 psia) 7.0 PORV closes (2285 psia) 10.0 AFW available 40.0 (a)No pressurizer safety valve action occurred

• A-45

2400 1000 ...

~*

BOO

\

2300 600 u IU en a

400

~

• -en 2200 200 0 Q,

PRESSURIZER PRESSURE .....

...cu- 0 ID

...=

t:IO

=

en en c.-,

cu a..

2100 *. -200

-400 2000 -600 SURGE FLOW

-BOD 0 10 20 30 40 Time, sec 19 640 cu cu lB 17 16 PRESSUR11ER LEVEL SURGE FLOW TEMP 620

...=-

~

cu cu cu a.

ecu N

15 600

...= I-cu en en 14 ...

1:111 cu

,_ =

c.-,

a..

13 5BO 0 10 20 30 40 Time, sec Figure A-23. ..System Response for LOFW With Anticipatory Reactor Trip Accident for 205-FA Plants A-46

Table A-24. Sequence of Events for :EWLB (177-FA Plants - Midland)

• Event 0.15-ft 2 break High pressure setpoint reached SG in affected loop dry Time, s 0.0 8.8*

9.0 Turbine tripped 9.4 Rods start to drop 9.5 Pressurizer safety valves open 11.0 Peak RCS pressure 11.S Pressurizer safety valves close 12.S I

A-47

PRESSURIZER LEVEL

-.... 25 610 IU

=-

IU IU

~

... 24 605 ....

J IU N

~

IU

...= =.

e IU en I-en IU a..

23 600 IU t:IG

I V) 22 595 D 4 8 12 16 20 Time, sec Figure A-24. System Response for FWLB for 177-FA Plant (Midland)

A-48

Table A-25. Sequence of Events for FWLB on Operating Plants (177-FA Plants)

Event Time, s FWLB occurs a.a SG in affected loop dry 5.a High pressure trip setpoint reached 5.6 Rods start to drop 6.a Pressurizer safety valve opens at 256a psia 7.4 Peak RCS pressure 9.2 SG in unaffected loop dry 2a Auxiliary feedwater starts <4a A-49

SURGE FLOI ., *

./

IQ

• -.,, 2700 2900 1200 1000 800 u

Q) en

=

0 600 ~

CD

=

en en 2500 400 ....

Q) 1:11 CD 200 ""=

a..

2300 PRESSURIZER o PRESSURE 2100 o 2 3 4 5 6 7 8 9 10 11 12 13 1 4 29 CD 28 27 621 620

~

CD CD 26 619 ....=

~

....CD IQ

.... 25 618  ::.

CD e

cu 3S"' 24 617

....CD CD N 23 PRESSURIZER 616 ....

00

.... =

=

en 22 LEVEL 615 en a..

Q) 21 614 0 2 3 4 5 6 7 8 9 10 11 12 13 l4 Figure A-25. System Response for FWLB dCCident for 177-FA Plants (Operating)

A-50

Sequence of Events for FWLB Table A-26.

• (205-FA Plants)

Event Time, s l.O-ft 2 break a.a High RCS pressure setpoint reached, RC pumps tripped 5.31 Turbine trip 5.81 Rods start to drop 5.96 Pressurizer safety valves open 7.0 Peak RCS pressure 9.a A-51

2000 ~

2700 SURGE FLOI 1500 u

!D en e

.c

• -caen 2500 1000 *-

Q ID

- PRESSURIZER ~

ID

== .....

en en PRESSURE ==

cu

..... 2300 500 "'

Q.,

2100 0 634 SURGE 633 TEMP

- 23 22 632 .....

631 ID cu == .

> ca cu .....

21 630 Qll Q,

..... 5

....cu 20 cu I-

..... 629 ID

==

en PZR ~

cu 19 LEVEL 628 ==

a.. "'

18 627 17 626 0 2 3 4 5 6 7 8 9 10 Time, sec Figure A-26. System Response for FWLB Accident for 205-FA Plants A-52