ML20202D192

Rev 2 to UFSAR Chapter 15 Transient Analysis Methodology

ML20202D192
Person / Time
Site:	Mcguire, Catawba, McGuire
Issue date:	12/31/1997
From:	DUKE POWER CO.
To:
Shared Package
ML20202D181	List: ML20202D177 ML20202D192
References
DPC-NE-3002-A, DPC-NE-3002-A-R02, DPC-NE-3002-A-R2, NUDOCS 9802170015
Download: ML20202D192 (190)

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ublish accepted versions of this Topical Report.

The accepted versions siall incorporate this letter and the enclosed Safety Evaluation between the title page and the abstract.

The accepted versions shall include an "A" (designating accepted) following the Topical Report identification symbol.

Hr. M. S. Tuckman Should NRC criteria or regulations change so that staff conclusions regarding g

the acceptability of the Topical Report are invalidated, DPC will be exper,ted 3{

to revise and resutait their documentation, or to submit justification for continued effective applicability of the Topical Report without revision of an '

their documentation. This completes NRC actions for TAC Nos. M94405, M94406 I;

M94407, AND M94408.

Sincerely, 4A I

Herbert N. Berkow, Dir ctor Project Directorate !!-2 Division of Reactor Projects - 1/l!

E Office of Nuclear Resctor Regulation 5

Docket Nos. 50-413, 50 414, 50-369 and 50-370

Enclosure:

Safety Evaluation cc w/ enc 1:

See next page

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McGuire Nuclear Station

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Duke Power Company Catawba Nuclear Station r

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Mr. Paul R. Newton Mr. Dayne H. Brown, Director Legal Department (PB05E)

Department of Environmental, Duke Power Company Health and Natural Resources

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422 South Church Street Division of Radiation Protection Charlotte,. North Carolina 28242-0001 P. O. Box 27687 Raleigh, North Carolina 27611-7687 r

County Manager of Mecklenburg County

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720 East Fourth Street Charlotte, North Carolina 28202 Ms. Karen E. Long Assistant Attorney General Mr. J. E. Snyder North Carolina Department of Regulatory Compliance Manager Justice Duke P0wer Company P. O. Box 629 McGuire Nuclear Site Raleigh, North Carolina 27602 12700 Hagers Ferry Road Huntersville, North Carolina 28078 Mr. G. A. Copp Licensing - EC050 J. Michael McGarry, III, Esquire Duke Power Company Winston and Strawn 526 South Church Street 1400 L Street, NW.

Charlotte, North Carolina 28242-0001 Washington, DC 20005 Regional Administrator, Region II Senior Resident Inspector U.S. Nuclear Regulatory Commission c/o U. S. Nuclear Regulatory 101 Marietta Street, NW. Suite 2900 Commission Atlanta, Georgia 30323 12700 Hagers Ferry Road Huntersville, North Carolina 28078 Elaine Wathen Lead REP Planner Mr. Peter R. Harden IV Division of Emergency Management Account Sales Manager 116 West Jones Street r

Westinghouse Electric Corporation Raleigh, North Carolina 27603-1335

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Power Systems Field Sales P. O. Box 7288 Mr. T. Richard Puryear Charlotte, North Carolina 28241 Owners Group (NCEMC)

Duke Power Company Dr. John M. Barry 4800 Concord Road Mecklenburg County York, South Carolina 29745 Department of Environmental Protection 700 N. Tryon Street Charlotte, North Carolina 28202 L

5 Duke Power Company McGuire Nuclear Station Catawba Nuclear Station cc:

Mr. M. S. Kitlan North Carolina Electric Membership Regulatory Compliance Manager Corporation Du ce Power Company P. O. Box 27306 4800 Concord Road Raleigh, North Carolina 27611 York, South Carolina 29745 Senior Resident inspector g

North Carolina Municipal Power 4830 Concord Road g

Agency Number 1 York, South Carolina 29745 1427 Headowwood Boulevard l

P. O. Box 29513 Mr. William R. McCollum Raleigh, North Carolina 27626-0513 Site Vice President Catawba Nuclear Station County Manager of York County Duke Power Company B

York County Courthouse 4800 Concord Road E

York, South r,arolina 29745 York, South Carolina 29745 l

Richard P. Wilson, Esquire Mr. T. C. McHeekin Assistant Attorney General Vice President, McGuire Site South Carolina Attorney General's Duke Power Company Office 12700 Hagers Ferry Road E

P. O. Box 11549 Huntersville, North Carolina 28078 E

Columbia, South Carolina 29211 Piedmont Municipal Power Agency 121 Village Drive Greer, South Carolina 29651 Saluda River Electric P. O. Box 929 Laurens, South Carolina 29360 Max Batavia, Chief Bureau of Radiological Health am South Carolina Department of Health and Environmental Control g!

2600 Bull Street Columbia, South Carolina 29201 gl I

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4 UNITED STATES s

j NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 306 2 4001

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SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION DUKE POWER COMPANY MCGUIRE NVCLEAR STATION DOCKET NO. 50-369 AND 50-370 CATAWBA NUCLEAR STATION DOCKET NOS. 50-413 AND 50-414 INTRODUCTION In its lettur of December 19, 1995, Duke Power Company (DPC), licensee for McGuire Nuclear Station, Units 1 and 2, and Catawba Nuclear Station, Units 1 and 2, notified the NRC of a change to an approved analysis methodology for the four nuclear units. DPC submitted additional information in its letter dated March 15, 1996.

The change relates to the modeling of accumulation in the lifting of the pressurizer safety valves or the main steam safety valves.

These safety valves provide overpressure protection of the primary system.

Currently, DPC is involved in steam generator replacements at the McGuire and Catawba stations.

During reviews of overpressure protection analyses, DPC identified that increases in the heat transfer area of replacement steam generators result in higher peak secondary pressures following turbine trip.

The higher peak pressures would require setpoints of safety valves to be lowered. DPC found, however, that with the change in accumulation modeling, the setpoints of the valves may remain consistent with those setpoints currently in the plant technical specifications.

VALVE INFORMATION The specific valves are listed below:

McGuire Nuclear Station:

Main Steam Safety Valves 1/2SV 2,3,8,9,14,15,20,21:

6" x 8" Crosby Style HA-65-FN, Built to ASME Section 111, 1971 Edition, Winter 1971 Addenda 1/2SV 4,5,6,10,11,12,16,17,18,22,23,24:

6" x 10" Crosby Style HA-65-FN, Built to ASME Section 111, 1974 Edition, Winter 1975 Addenda (originally purchased for the Marble Hill Nuclear Plant),

and recertified to ASME Section III, 1971 Edition, Winter 1971 Addenda.

ENCLOSVRE

I

-L Pressurizer Safety Valves Size 6M6 (6" inlet, "M" orifice, 6" outlet) Crosby Style HB-BP-86.

Valves or<ginally installed with loop seals, but modified in 1992 to drain the loop seal and modify valve internals for sealing l

against steam.

The valves were built to ASME Section III, 1971 Edition, addenda through the 1972 Addenda.

Catawba Nuclear Statfon:

Main Steam Safety Valves Dresser Model 3787, built to ASME Section !!!, 1974 Edition, Summer 1975 Addenda.

Pressurizer Safety Valves Dresser Model 31749A, built to ASME Section Ill,1974 Edition, Summer 1975 Addenda.

These valves do not have loop seals.

MODELING METHODOLOGY The current Final Safety Analysis Report (FSAR) Chapter 15 analyses that support the McGuire units and the Catawba units are detailed in the topical report OPC-NE-3002-A, "FSAR Chapter 15 System Transient Analysis Methodology."

-E The NRC-approved methodology says that the pressurizer safety valves and the 5

main steam safety valves are modeled with lift, accumulation, and blowdown assumptions which maximize the pressurizer pressure or minimize the secondary am (main steam system) pressure.

Lift is the actual travel of the valve disc g

away from the closed position when the valve is relieving.

Accumulation is the pressure increase in the system pressure over the actual valve set pressure, frequently referred to as " overpressure," and is usually expressed l

as a percentage of set pressure.

Blowdown is the difference between actual u

lift pressure of a safety valve and actual reseating pressure, usually expressed as a percentage of set pressure.

The requirements of Section III of a

the American Society of Mechanical Engineers (ASME) Bof fer and Pressure Vessel l

Code (the Code), 1971 Edition, and similar in later editions, paragraph NB-7614, gives the operating requirements for Class I safety valves (pressurizer safety valves) as follows:

NB-7614.1 Anti-Chattering and Lift Requirements. Safety valves shall be designed and constructed without 3

chattering and to attain full lift at a pressure no u

greater than 3 percent above their set pressures.

NB-7614.2 Blow Down Requirements.

Safety valves shall be l

set and adjusted to close after blowing down at a pressure not lower than 5 percent of the set pressure.

The valves shall be adjusted, sealed and marked by the Manufacturer, g

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3 NS-1614.3 Popping-Point Tolerance.

The popping-point tolerance shall not exceed 1 percent, plus or minus, of the set pressure for pressure over 1000 psi.

The similar design and operating requirements for Class 2 safety valves (main steam safety valves) given in paragraph NC-7614 are as follows:

NC-7614.1 Lift and Blowdown.

Safety valves shall operate without chattering and to attain full lift at a pressure no greater than 3 percent above their set pressure. After blowing down, all valves sht11 close at pressures not lower than 95 percent of their set pressures...

NC-7614.2 Popping-Pressure Tolerance.

(a) The popping-pressure tolerance (plus or minus) from the set pressure of safety valves shall not exceed the following:

... I percent for pressures over 1000 psi.

The approved models assume that lifting of the safety valves is a linear opening beginning at the setpoint and reaching full open at a pressure corresponding to the setpoint plus a conservatively assumed accumulation of one to three percent of the lift pressure setpoint.

For example, a pressurizer safety valve with a setpoint of 2500 psig and three percent accumulation would reach full open at no higher than 2575 psig.

DPC asserts that the models are conservative, but that the actual valve performance is not represented.

Both sets of safety valves, thougn different models and different manufacturer, are best characterized as having a popping-open response.

l HQDRING CHANGE DPC proposes to use a pop-open modeling approach rather than a linear ramping open approach. The revised modeling assumes that the safety valves pop open to a full-open position in 0.5 seconds after the drifted lift setpoint is reached. The assumption is based on testing and a review of tests that DPC engineering and the valve manufacturers (Crosby and Dresser) conducted.

Pressurizer Safety Valves The pressurizer safety valves were tested as part of a performance test program conducted by the Electric Power Research Institute (EPRI) to meet action item II.D.1, " Performance Testing of Boiling-Water Reactor and Pressurized-Water Reactor Relief and Safety Valves,' of NUREG-0737,

' Clarification of TMI Action Plan Requirements.' Multiple tests of Dresser Model 31709NA and 31739A and Crosby HB-BP-86 6N8 pressurizer safety valves, varying parameters such as pressurization rate, system media, and ring settings, indicated opening times of less than 0.1 second. Such a rapid opening time is characteristic of a popping-open action. The test results were used by licensees to correlate performance to site-specific similar valves.

p 4

Main Stean Safety Valves DPC tested all of the McGuire Station main steam safety valves at Crosby's high flow test loop to determine unique ring settings for each valve.

The m

tests were to assure blowdown performance within a range less than or equal to l

ten percent.

The test simultaneously recorded (1) inlet pressure Although determin)ing opening response time was not th pressure, and (3 System.

the times were recorded. The opening timas ranged from 0.060 second to 0.110 l

second.

Graphs of the opening of several of the valves were included in DPC's letter of March 15, 1996. These graphs show a rapid popping-open action. DPC 3

correlated these tests and the measured opening times with the tests performed E.

by EPRI and concluded that the main steam safety valves would pop open and be fully open within the 0.5 second assumed in the new model for overpressure protection-a E

The main steam safety valves installed in Catawba Station have not been tested in the same manner as the McGuire Station valves.

Therefore, DPC reviewed 3

data for similar valves that were part of the EPRI testing program. Selection u

of the 0.5 seconds for full opening is over 500 percent slower than the full opening time observed for the pressurizer safety valves. Dresser engineering a

concurred with the assumption that the Catawba Station Model 3787 main steam safety valves will open in less than 0.5 second.

g EVALUATION Pressure relief valves of various designs can modulate open and closed over the entire or a substantial portion of the lift, or modulate open over only a E

small portion of the lift and then open suddenly to the fully open position.

3 The pressurizer safety valves and the main steam safety valves installed in the McGuire Station and Catawba Station are of the full-lift type i.e.

open for a small portion of the lift and then pop open to the full-(open, they l

position).

DPC's determination that the valves wi?1 fully open within 0.5 seconds includes conservatism when compared to the test data used to validate the modeling assumption.

For safety valve design, the ASME Code,Section III E

(see above), requires a popping-point tolerance of plus or minus one percent 5

of the setpoint of the valves and requires that the valves be fully open at no greater than three percent above the setpoint.

DPC has demonstrated through testing and correlation of valves not specifically tested that a rapid popping action is characteristic of the valves.

For these valves, there will be a short period when the valves first l

begin to lift where the closing forces are initially greater than the opening forces (i.e., the modulating portion of the lift.

continues to act on the disc, the opening forces)become greater than theAs the syste 3

closing forces, and the disc rises sharply. The disc moves to the full open E'

position in a very short period of time, almost instantaneously, by design.

Therefore, DPC may use a value of 0.5 second as the time from when the system an i pressure reaches the setpoint of the valves (adjusted in the model for an I

assumed drift of three percent) to the full opening and full relieving capacity.

In making this change to the model, all requirements of the ASME Code,Section III, must be met.

l

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QNCLUSION Valve Design Characteristics An assumption of 0.5 second as the time to reach the full-open position for the pressurizer safety valves and the main steam safety valves is acceptable

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as it relates to the design characteristics of these valves.

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Overpressure Protectfon Analysis l

The licensee stated in its letter dated December 19, 1995, that the proposed change of the safety valve opening characteristics in the methodology for 1

1 analyzing system transients is needed for McGuire and Catawba plants. The

(

current methodology as documented in DPC-NE-3002-A assumes that the safety valves are opened at their fully open position when the system pressures are corresponding to their lift set)oints plus an accumulation allowance. This is i

a conservative modeling approac1. However, the licensee finds that a change

(

of the safety valve opening characteristics to popping-0)en of the safety

)

valves at their lift setpoint is needed to accommodate t1e proposed change of the safety valve allowable setpoint drift and the design of the replacement

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steam generators at McGuire and Catawba plants.

For reasons discussed in the

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above paragraphs, the staff considers that the proposed change of safety valve opening characteristics in DPC-NE-3002-A is reasonable and acceptable, i

i Principal Contributor:

P. Campbell C. Liang R. Martin Date: April 26, 1996

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NUCLEAR REZULATORY COMMISSION

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WASHINoToN, o.C. 306 4 0001 December 28, 1995 Mr. M. S. Tuckman Senior Vice President Nuclear Generation Duke Power Company P. O. Box 1006 Charlotte, NC 28201-1006

SUBJECT:

SAFETY EVALUATION FOR REVISION 1 TO TOPICAL REPORT DPC-NE-3002,

'FSAR CHAPTER 15 SYSTEM TRANSIENT ANALYSIS METHODOLOCY" MCGUIRE NUCLEAR STATION, UNITS 1 AND 2; AND CATAWBA NUCLEAR STATION, UNITS 1 AND 2 (TAC NOS. M89944, M89945, AND M89946)

Dear Mr. Tuckman:

By letter dated July 18, 1994, Duke Power Company (DPC or licensee) submitted DPC Topical Report DPC-NE-3002, Revision 1, 'FSAR Chapter 15 System Transient Analysis Methodology," dated June 1994, for NRC review. The report describes changes to the DPC transient analysis methodology.

These changes are due to:

(1) steam generator replacement for the McGuire and Catawba stations. (2) methodology changes documented in DPC-NE-3000P, Revision 1, and (3) correction of typographical errors.

In the original report, the steam generator tube been appr(oved and was included in this revision.SGTR) transient methodology was However, it has since rupture The staff finds DPC-NE-3002, Revision 1, to be acceptable for referencing in McGuire and Catawba licensing applications to the extent specified and under the limitations stated in DPC-NE-3002, Revision 1, and the associated NRC Safety Evaluation.

The enclosed Safety Evaluation defines the basis for accepting this To)ical Report.

The staff was assisted in its review by International Tec1nical Services ITS) Inc. The ITS Technical Evaluation Report (TER ITS/NRC/95-5) is also(enclosed.

When the Topical Report is referenced in a license application, the staff does not intend to repeat its review of the matters described in the Topical Report that were found acceptable, except to ensure that the material presented is-a>plicable to the specific plant involved.

Staff acceptance applies only to t1e matters described in the report.

In accordance with procedures established in NUREG-0390, DPC must )ublish accepted versions of this Topical Report.

The accepted versions stall incorporate this letter and the enclosed Safety Evaluation between the title page and the abstract.

The accepted versions shall include an -A (designating accepted) following the Topical Report identification symbol.

I l

Mr. H. S. Tuckman December 28, 1995 Should NRC criteria or regulations change so that staff conclusions regarding the acceptability of the Topical Report are invalidated, DPC will be expected to revise and resubmit their documentation, or to submit justification for continued effective applicability c' the Topical Report without revision of l

their documentation.

This completes NRC actions for TAC Nos. H89944, H89945 and M89946.

Sincerely, db4 Wua k I

Robert E. Martin, Senior Project Manager l

Project Directorate !!-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation Docket Nos. 50-369, 50-370 50-413 and 50-414

Enclosures:

1.

Safety Evaluation l

2.

Technical Evaluation Report ITS/NRC/95-5 cc w/ enc 1s:

See next page I

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McGuire Nuclear Station Duke Power Company Catawba Nuclear Station cc:

Mr. Paul R. Newton Mr. Dayne H. Brown, Director Duke Power Company, P805E Dezartment of Environmental, 422 South Church Street 4ealth and Natural Resources Charlotte, North Carolina 28242-0001 Division of Radiation Protection P. O. Box 27687 County llanager of Mecklenburg County Raleigh, North Carolina 27611-7687 720 East Fourth Street Charlotte, North Carolina 28202 Ns. Karen E. Long Mr. J. E. Snyder Assistant Attorney General Regulatory Compliance Manager North Carolina Department of Duce Power Company Justice McGuire Nuclear Site P. O. Box 629 12700 Hagers Ferry Road Raleigh, North Carolina 27602 Huntersville, North Carolina 28078 Mr. G. A. Copp J. Michael McGarry, III, Esquire Licensing - EC050 Winston and Strawn Duke Power Company 1400 L Street, W.

526 South Church Street Washington, DC 20005 Charlotte, North Carolina 28242-0001 Senior Resident Inspector Regional Administrator, Region !!

c/o U. S. Nuclear Regulatory U.S. Nuclear Regulatory Commission Commission 101 Marietta Street, W. Suite 2900 12700 Hagers Ferry Road Atlanta, Georgia 30323 Huntersville, Nntti Carolina 28078 Elaine Wathen Mr. Peter R. Harden, IV Lead REP Planner Account Sales Manager Division of Emergency Management Westinghouse Electric Corporation 116 West Jones Street Power Systems Field Sales Raleigh, North Carolina 27603-1335 P. O. Box 7288 Charlotte, North Carolina 28241 Dr. John M. Barry Mecklenburg County Department of Environmental Protection 700 N. Tryon Street Charlotte, North Carolina 28202 i

I Duke Power Coseany McGuire Nuclear Station E

Catawba Nuclear Station W

l Cc:

E l

Mr. Z. L. Taylor North Carolina Electric Membership 5

Regulatory Compliance Manager Corporation Duke Power Compaisy P. O. Box 27306 4800 Concord Road Raleigh, North Carolina 27611 l

York, South Carolina 29745 Senior Resident Inspector North Carolina Municipal Power 4830 Concord Road E

Agency Number 1 York, South Carolina 29745 E

1427 Meadowwood Boulevard P. O. Box 29513 Mr. William R. McCollum a

Raleigh, North Carolina 27626-0513 Site Vice President l

Catawba Nuclear Station County Manager of York County Duke Power Company York County Courthouse 4800 Concord Road E

York. South Carolina 29745 York, South Carolina 29745 5

Richard P. Wilson, Esquire Mr. T. C. McNeekin g

Assistant Attorney General Vice President, McGuire Site 3

South Carolina Attorney General's Duke Power Company Office 12700 Hagers Ferry Road P. O. Box 11549 Huntersville, North Carolina 28078 Columbia, South Carolina 29211 Piedmont Municipal Power Agency E

121 Village Drive 5

Creer, South Carolina 29651 l

Saluda River Electric P. O. Box 929 Laurens, South Carolina 29360 Max Batavia, Chief Bureau of Radiological Health South Carolina Department of a

Health and Environmental Control l

2600 Bull Street Columbia, South Carolina 29201 I.

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NUCLEAR RE20LATORY CEMMISSION o

.P WASHINGTON, D.C. 30046 4 001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION TOPICAL REPORT DPC-NE-3002. RE'llSION 1. "FSAR CHAPTER 15 SYSTEM TRANSIENT ANALYSIS METHODOLOGY" DUKE POWER. COMPANY MCGUIRE NUCLEAR STATION. UNITS 1 AND 2 CATAWBA NUCLEAR STATION. UNITS 1 AND 2

[]QQET NOS. 50-369. 50-370 50-413. AND 50-414

1.0 INTRODUCTION

In Revision 1 of the Topical Report DPC-NE-3002 entitled "FSAR Chapter 15 Systtw Transient Analysis Methodology" dated June 1994 (Reference 1) Duke Power Company (DPC) documented revisions reflecting changes due to (i) replacement of steam generators (SGs) for the McGuire Units 1 and 2 and Catawba Unit 1 stations, and (ii) methodology changes documented in DPC-NE-3000, Revision 1 (Reference 2). Corrections of typographical errors were also included. Additional information was provided in Reference 3.

The original Topical Reports DPC-NE-3000 (Reference 4) and DPC-NE-3002 (Reference 5) were reviewed and approved, subject to certain conditions (References 6 and 7).

Steamline break, rod ejection, dropped rod, and boron dilution events were not part of this review since these events are documented in DPC-NE-3001 (Reference 8), which has been. reviewed and approved.

2.0 REPORT SM4ARY DPC-NE-3002 (References 1 and 5) contains DPC's qualitative approach to performance of FSAR Chapter 15 type analysis for the McGuire and Catawba stations using methodology utilizing the RETRAN and VIPRE-01 computer codes described in DPC-NE-3000.

It does not address justification, qualification, or demonstration of the approaches taken for the analysis. However, it does state the process DPC intends to use in determining initial and boundary conditions, transient assumptions and scenarios, and code models used in licensing applications for transient analysis.

Revision 1 of DPC-NE-3002 documents changes due to (i) the replacement of steam generators for McGuire Units 1 and 2 and Catawba Unit 1, and (ii) minor methodology changes presented in Revision 1 of DPC-NE-3000. Typographical errors were also correct (d.

Changes include analysis objectives, pressurizer ENCLOSURE 1

d ll and SG models, initial and boundary conditions, transient assumptions in terms of system component availability, and the use of statistical core design (SCD)

E methodology for DNBR computation.

E 3.0 EVALUATION Acceptability of DPC's revisions of RETRAN models and assumptions for thermal-hydraulic calculations of FSAR Chapter 15 transient analysis of its McGuire/ Catawba (H/C) plants is discussed below. Only those items which bear l

analytical or safety significance are discussed.

Those items of a non-technical nature are not discussed.

3.1 Chanaes in McGuire and Catawba RETRAN Methodolooy The RCTRAN base models for M/C plants were qualified in DPC-NE-3000 and its Revision 1 for both best estimate and licensing-type, non-LOCA applications, l

subject to limitations described in the Safety Evaluation (SE) (References 6 and 9).

Note that DPC's submittal of August 9,1994, was < dentified then as Revision 3 to the DPC-NE-3000 report. That submittal has since been E

renumbered as Revision I to the original DPC-NE-3000 report by DPC's letter of E

September 12, 1995.

The approved version of the original DPC-NE-3000 report was issued by DPC on August 8, 1995 (Reference 6),

The NRC's SE for a

Revision 1 to the original DPC-NE-3000 report was issued on December 27, 1995 g

(Reference 9).

A change which impacted the documentation of DPC-NE-3002 was a change in the l

pressurizer modeling described in DPC-NE-3000, Revision 1.

T?, all sections W

that related to the previous modeling description were revisea Also included in the revision of the RETRAN methodology is modelin$1s of the of a Babcock & Wilcox (B&W) feedring steam generator (FSG) model. Deta FSG nodalization and other associated changes due to SG replacement are presented in Reference 2.

A significant inanct is expected in the Feedwater System Pipe Break analysis results due to tie design and location of the main feedwater nozzles, which is discussed in Section 3.3 of this evaluation.

3.2 SCD Transients The core thermal-hydraulics for most of the transients considered in this a

Topical Report are analyzed using the DPC-developed and NRC-approved SCD g

methodology (Reference 10).

For these transients, certain initial conditions used in the transient stfety analysis are selected to be at nominal conditions, as qualitatively defined in the subject report, since the l

uncertainty associated with the initial conditions is accounted for in the 500 nthod.

Of those transients for which a DNBR computation is performed, there remain two transients (startup of an inactive reactor coolant pump at an incorrect temperature and steam line break) for which DNBR calculations are not n

performed using the 500 methodology. With this revision, DPC stated its l

intent to use the SCD methodology for reactor coolant pump (RCF) locked rotor, and steam generator tube rupture (SGTR).

I e

I Although in the locked rotor analysis the core flowraie is expected to fall below the minimum SCD parameter value, a statistical Monte Carlo propagation is performed to ensure that the statistical design limit remains acceptable.

This approach was approved provided that the range of applicability of the critical heat flux DPC stated that the(CHF) correlation is not violated.

In the SGTR analysis, range of applicability remained valid for SCD parameters.

3.3 Revised FSAR Transient Analysis In this section those transient analyses.-in which significant revisions are' proposed, are highlighted and other revisions are briefly discussed.

3.3.1 Increase in Heat p - val-by the Secondary System Two transients in this category, which incorporated revisions, are

( ))Feedwater System Malfunction Causing an increase in Feedwater Flow, and (i

Excessive Increase in Secondary Steam Flow.

In both cases revisions are l

l m nor since the changes are primarily editorial reflecting methodology changes in DPC-NE-3000, Revision 1, and, therefore, are acceptable.

l 3.3.2 Decrease in Heat Removal by the Secondary System All four transient analyses are affected by revisions in this category: turbine trip, (1

, an (iv) feedwater system pipe break. Turbine trip is analyzed with respect to peak RCS and secondary side pressure, and the others are analyzed with respect to peak RCS pressure and DN8 and/or long-term core coolability (potential for

(

hot leg boiling).

4 3.3.2.1 Turbine Trio A change in the assumption regarding the )ressurizer (PZR) level control is introduced. DPC stated that the use of tw level control in manual with the PZR heaters locked on will be worse with respect to high primary system

[

pressure than the case when the PZR level control is in automatic.

The staff concurs with this assumption.

I 3.3.2.2 Loss of Offsite Power In addition to the potential challenges to peak RCS pressure, peak secondary side pressure, and DN8, DPC will analyze this transient with respect to long-term core cooling capability.

Therefore, a new section was added to the report describing the analysis to demonstrate that natural circulation can be established after loss of offsite power.

Transient assumptions are j

reasonable. With respect to the other transient objectives, changes

. introduced are benign.

I 3.3.2.3 Loss of Normal Feedwater Assumptions regarding the initial SG inventory were revised.

in the new approach, low instead of high SG 1evel is assumed to maximize the secondary pressure. This is expected to cause an earlier reactor trip on the SG low-low

[

9

I l 1evel. Tho downward adjustment of the initial SG 1evel introduces competing effects with raspect to predicted peak primary and secondary pressures and DNBR.

This event is currently not a limiting transient in this category and is a

bounded by the turbine trip event. Therefore, its analysis is not required.

l However, OPC stated that an analysis may become necessary in the future due to hardware or methodology changes.

In that event, DPC will need to perform sensitivity studies with respect to initial condition selections to ensure E

conservatism in the analysis.

E 3.3.2.4 Feedwater System Pioe Break This transient is significantly impacted by implementation of the feedring steam generators, and requires three major assumption changes as a direct l

result of '.he design and location of the main feedwater nozzles. OPC's 4

discussion of assumption changes and the impact of changes in transient results was reviewed and fouad to be reasonable.

The loss of oft' site power coincident with reactor trip is assumed, resulting in RCP trip and delay in the startup of the diesel generators for safety injection.

Carly main steam isolation valve (MSIV) closure was determined to a

be conservative in terms of earlier faulted SG dryout.

Thus, in the revised l

assumptions, MSIV closure occurs coincident with turbine trip, which occurs on loss of offsite power.

OPC's approach to the analysis of this event is g

acceptable.

3.3.3 Deg ease in Reactor Coolant System Flowrate Three transients analyzed in this catego y are:

(1) partial loss of forced l

reactor coolant (RC) flow (2) complete loss of forced reactor coolant flow, and (3) reactor coolant pump locked rotor.

I Revisions to both the complete and partial loss of forced RC flow are editorial changes and are acceptable.

3.3.3.1 Reactor Coolant Pumo locked Rotor As stated in Section 3.2 DNBR for this event will be analyzed using the SCD e

methodology. Therefore, affected parameters are initially set to nominal l

values instead of assuming conservative values. OPC provided the explanation of the applicability of the 500 methodology for this transient (Reference 3) and the staff finds the explanation to be acceptable (see also Section 3.2).

g OPC stated that cases with and without loss of offsite power coincident with the turbine trip will be analyzed.

As stated in the SE (Reference 7) for DPC-NE-3002 (Reference 5), the assumption of 120% of design pressure is not an acceptable limit. OPC is required to use 110% of design pressure, as stated in the previous revision.

I

s j

3.3.4 Reactivity and Power Distribution Anomalies 1

DPC added ti,e possibility of reactor trip on high pressurizer pressure in

]

addition to the high neutron flux for completeness.

3.3.5 Increased Reactor coolant Inventerv Inadvertent operation of ECCS h ring power operation is the only transient analyzed. Although DN8 is a primary concern, since a potential for

~ pressurizer overf'11. exists during this-event, DPC added a new section to address that concern for PZR overfill leading to water relief through the PZR e

Safety Valves (PSVs). The acceptance criter< on for this analysis is the minimum water relief temperature to assure PSV~ operability.

8 The Standard Review Plan suggests the use of full power unless a lower power can be justified.

In Reference 3, DPC assumes zero power in this analysis for conservatism.

This-is because if overfill occurs at lower initial power, then the water relief temperature is more likely to be less than tre acceptance i

criterion. Therefore, DPC selected the initial and boundary ccMitions in i

order to minimize relief temperature. The staff finds this approach to be reasonable and acceptable.

3.3.6' Decrease in Reactor Coolant Inventory l

Inadvertent opening of a pressurizer safety or relief valve and steam generator tube rupture events are the two transients analyzed.in this

)

category.

Proposed revisions to the inadvertent opening of a pressurizer.

t safety or relief valve are editorial changes, i

3.3.6.1 Steam Generator Tube Rugigtg j

The steam generator tube rupture-(SGTR) documented in DPC-NE-3000, based event was not part of the original 4

review since the transient methodology use of the RETRAN computer code.was approved only for non-LOCA ap>11 cations.

This restriction regarding performance of SGTR analysis with RETRAt (Item vii of RETRAN SER (Reference 11)) applies to app 1tcations that-encounter two-phase flow in the primary loop.-which does occur in many SGTR scenarios.

t In the limited review documented in Reference 12 DPC received approval for an SGTR analysis of the worst-case offsite dose scenario using RETRA1 for Catawba l

. Nuclear Station, Units 1 and 2. ' Justification was provided in a qualitative-i o

i '

manner by DPC (Reference 13) on each of the items cited under restrictions and r

limitations on the use~of RETRAN in its SE. There is assurance that the use 1

of the-code for-that particular scenario was acceptable since DPC stated that two-phase-flow was not encountered in the primary loop.

Although NRC a> proval was specific to Catawba Units 1 and 2, as considered in F

DPC-NE-3000, t to Catawba and McGuire plants, for the purpose of analysis qualification,-are interchangeable.

Therefore, DPC stated that NRC approval of the SGTR analysis using RETRAN should be ap>11 cable to the McGuire plant.

analysis (Reference 3).

The staff concurs witt DPC's statement, so long as 4

__-_.~;..:.__._,,,

f a l the scenario is essentially the same and no two-phase flow conditions are encountered in the RCS primary loops.

l The DNBR will be computt.d using the 500 methodology (see Section 3.2).

4.0 CONCLUSION

S AND LIMITATIONS Revision I to the DPC Topical Report DPC-NE-3002 and the DPC responses to NRC questions and other supporting documents cited in Section 5.0 were reviewed.

l Review of these documents focused upon evaluation of acceptability of the proposed changes and the perceived impact of these changer, As stated earlier, steamline break, rod ejection, dropped rod, and baron dilution events were not part of this review.

Subject to the foregoing, DPC's proposed revision of its approach to FSAR Chapter 15 transient analysis, as documented in Revision 1 of DPC-NL-3002 and its supporting document, was found to be acceptable subject to the following l

limitations:

1.

The acceptability of the use of DPC's approach to FSAR analysis is subject to the conditions of SEs on all aspects of transient analysis 3

and methodologies (DPC-NE-3000, DPC-NE-3001, DPC-NE-3002, DPC-NE-2004, E

and DPC-NE-2005) as well the SEs on the RETRAN and VIPRE-01 computer codes.

I 2.

There are scenarios in which an SGTR event may result in loss of subcooling and the consequent two-phase flow conditions in the primary

system, in such instances, the use of RETRAN is not acceptable without a detailed review of the analysis.

3.

In the future, if hardware or methodology changes, selection of limiting E

transients needs to be reconsidered, and DPC is required to perform g

sensitivity studies to identify the initial conditions in such a way to avoid conflict between transient objective, such as DNB and worst-case primary pressure.

l 4.

It is emphasized that, when using the SCD methodology to determine DNBR, the range of applicability of the selected critical heat flux correlation must not be violated.

5.

DPC's assumption of 120% of design pressure as part of the acceptance a

criteria for Reactor Coolant Pump locked Rotor is not acceptable; DPC is g

required to use 110% of design pressure for that limit.

g Principal Contributor:

L. Lois Date:

December 28, 1995 I

1Il

I r

7-

[

5.0 REFERENCES

l l

1.-

Letter from M. S. Tuckman (DPC) to NRC, dated July 18, 1994, i

transmitting "FSAR Chapter 15 System Transient Analysis Methodology, DPC-NE-3002 " Revision 1, June 1994.

l 2.

Letter from M. S. Tuckman (DPC) to NRC, dated August 9, 1994, l

transmitting " Duke Power Company, The Thermal-Hydraulic Transient Analysis Methodology Oconee Nuclear Station, McGuire Nuclear Station, Catawba Nuclear Station," DPC-NE-3000-P, redesignated as Revision 1, t

e j.

August 1994.

3..

Letter from M. S. Tuckman (DPC) to NRC, " Topical Report DPC-NE-3002, l

"FSAR Chapter 15 System Transient Analysis Methodology," Responses to NRC Questions," August 18, 1995.

i 4

4.

Letter from H. B. Tucker (DPC) to NRC, dated September 29, 1987, transmitting " Duke Power Company, The Thermal-Hydraulic Transient Analysis Methodology, DPC-NE-3000, July 1987" for Oconee Nuclear Station, McGuire Nuclear Station, and Catawba Nuclear Station.

5.

LetterfromH.B. Tucker (DPC)ionofthereport"DPC-NT-3002-A,FSAR to NRC, dated August 17, 1992 transmitting the approved vers Chapter 15 System Transient Analysis Methodology."

6.

Letter from T. A. Reed:(NRC), to H. B. Tucker (DPC), dated November 15, 1

1991, transmitting " Safety Evaluation on Topical Report DPC-NE-3000, Thermal-Hydraulic Transient Analysis Methodology," as transmitted with the approved version of the report (DPC-NE-300C-PA) by M. S. Tuckman's letter of August 8, 1995.

7.

Letter from T. A. Reed;(NRC) to H. B. Tucker (DPC), dated November '5, 1991, " Safety Evaluation on Tulical Report DPC-NE-3002, FSAR Chapter 15.

System Transient Analysis Methodology," as transmitted with the approved-l version of the report (DPC-NE-3002-A) by H. B. Tucker's letter of August 17, 1992..

+

l 8.

Letter from H. B. Tucker (DPC), to NRC, dated August 17, 1992, transmitting the approved version of " Multi-dimensional Reactor '

Transients and Safety Analysis Physics Parameters Methodology,"

DPC-NE-3001PA, November 1991.

9.-

Letter from R. E. Martin (NRC), to M. S.- Tuchman (DPC), dated i

December 27, 1995, transultting " Safety Evaluation for Revision 1 to ID Topical Report DPC-NE-3000-P, Thermal-Hydraulic Transient Analysis Methodology."

10.

Letter from G. M. Holahan (NRC) to H.B. Tucker (D?C), deted February.24, 1995,-" Acceptance for Referencing of the Modified Licensing Topical Report, DPC-NE-2005P, Thermal-Hydraulic Statistical Core Design

Methodology," as transmitted with M. S. Tuckman's letter of August 8, r

1995, " Issuance of Approved Version of DPC-NE-2005P (DPC-NE-2005P-A)."

L l-

~

.2 -.

. ~......

_ REFERENCES (continued)

I 11.

Letter from C. O. Thomas (NRC) to T. W. Schnatz (UGRA), " Acceptance for Referencing of Licensing Topical Reports EPRI CCH-5, RETRAN-A Program for One Dimensional Transient Thermal Hydraulic Analysis of Complex l

Fluid Flow Systems," September 2, 1984.

12.

Letter from R. E. Martin (NRC) to M. S. Tuckman (DPC), " Safety E

Evaluation for the Catawba Nuclear Station, Units 1 and 2, Steam E

Generator Tube Rupture Analysis," May 14, 1991.

13.

Letter from H. B. Tucker (DPC) to NRC, dated December 7, 1987, " Catawba Nuclear Station Steam Generator Tube Rupture Analysis."

I I

I' I

I I

I I

I I

I I

I

ITS/NRC/95 5 TECHNICAL EVALUATION:

FSAR CHAPTER 15 SYSTEM TRANSIENT ANALYSIS METHODOLOGY OPC NE 3002 REVISION 1 FOR DUKE POWER COMPANY P.B. Abramson l

H. Komoriya i

Prepared for U.S. Nuclear Regulatory Commission Washington, D.C.

20555 Under NRC Contract No. NRC-03-90 027 FIN No. L1318 1

Y International Technical Services, Inc.

420 Lexington Avenue New York, NY, 10170 ENCLOSURE 2 o

ITS/NRC/95 5 I

TECHNICAL EVALUATION:

g FSAR CHAPTER 15 SYSTEM TRANSIENT ANALYSIS METHODOLOGY g

TOPICAL REPORT DPC NE-3002 REVISION 1 f.08 DUKE POWER COMPANY MCGUIRE AND CATAWBA NUCLEAR STATIONS

1.0 INTRODUCTION

In Revisicn 1 of the topical report entitled "FSAR Chapter 15 System Transient Analysis Methodology," DPC NE 3002, dated June 1994 (Ref.1). Duke Power Company (DPC) documented revisions reflecting changes due to (i) replacement of steam generators for the McGuire and Catawba Unit I stations lj, and (11) methodology changes documented in DPC-NE 3000 Rev. 3 (Ref.

2.

Additiona)l Corrections of typographical errors were also included.

3 information was provided in Reference 3.

E, The original topical reports DPC-NE 3000 (Ref. 4) and DPC NE-3002 (Ref. 5) were reviewed and approved, subject to certain conditions (Refs 6 and 7).

l DPC NE-3002 (Refs. I and 5) contains DPC's qualitative approach to selection of initial and boundary conditions, transient assumptions and computer code models for use in performing transient analysis of FSAR Chapter 15 accidents for McGuire and Catawba Nuclear Stations.

The re) ort 'does not contain any justification, qualification or demonstration af selections.

l Steam line break, rod ejection, dropped rod and boron dilution events were not part of this review since these events are documented in DPC NE 3001 l

l (Ref 8) which has been reviewed and approved.

2.0 SUPNARY i

DPC NE-3002 contains DPC's qualitative approach to performance of FSAR Chapter 15-type analysis for the McGuire and Catawba stations using methodology utilizing the RETRAN and VIPRE 01 computer codes described in DPC-NE-3000, it does not address justification, qualification or l!

demonstration of the approaches taken for analysis.

However, it does state j

the process they intend to use in determining initial A id boundary conditions, transient assumptions and scenarios and code mocels used in g

licensing-type transient analysis.

E Revision 1 of DPC-NE-3002 documer.ts changes due to (1) the repitcoment steam en 1 generators for McGuire and Catawba Unit I and (ii) minor methodology changes ll presented in Revision 3 of DPC NE-3000.

Typographical errors are also corrected.

Changes include analysis objectives, pressurizer and SG models, 1

4 t

initial and boundary conditions, transient assumptions in terms of system

}

l component availability, and the use of statistical core design methodology i

for DNSR computation.

3 i

3.0 EVALUATION Acceptability of DPC's revisions of RETRAN models and assumptions for j

thermal hydraulic calculations of FSAR Chapter 15 transient analysis of its McGuire/ Catawba (WC) plants is discussed below. Caly those items which bear analytical or safety significance are discussed.

Those items of a non.

i technical nature are not discussed.

(

3.1=

thanaan in Metuire and Cat

• RETRAN Nath 4=1ony The RETRAN base models for WC plants were qualified in DPC NE 3000 and its 1

Revision 3 for both best estimate and licensing type non LOCA applications, subject to limitations described in the SER and TER (Refs. 6 and 9).

)

A change which impacted the documentation of DPC NE 3002 was a change in PZR modeling described in DPC NE 3000 Rev. 3.-

Thus, all sections which related I

to prev'ous modeling description were revised.

i

)

Also included in the revision of the RETRAN methodology is modeling of a BW feedring steam generator (FSG) Model.

Details of the FSG nodalization and other associated changes due to $G-replacement are presented in Reference 2.

A significant impact is expected in the Feedwater System Pipe Break analysis results due to the design and location of the main feedwater nozzles, which i

is discussed in Section 3.3. of this report.

i i

3.2 SCD Transiente i

i The core thermal hydraulics for most of the transients considered in this j

topical report are analyzed using the DPC developed and NRC approved SCD i

methodology (Ref. 10).

j For these transients, certain initial conditions used in.the transient safety analysis are selected to be at nominal conditions, as i

qualitatively defined in the subject report, since the uncertainty associated i

i with the initial conditions is accounted for in the 500 method, i

I Df those transient for which a DN8R computation is performed, there remain I

i two transients (startup of an inactive reactor coolant. pump at an incerrect temperature and steaa line break performed using the SCO methodolog)y. for which DNBR calculations are not t

With this revision, DPC stated its intent to use the SCO methodology for RCP Locked Rotor and SGTR.

Although in the Locked Rotor analysis the core flowrate is expected to fall 2

below the minimum SCO parameter value, a statistical Monte Carlo propagation 1s performed to ensure that the statistical design limit remains acceptable.

This approach was approved provided that the range of applicability of the critica' heat flux-(CHF) correlation is not violated, 4

t i

in the SGTR analysis, DPC stated that the range of applicability remained i

valid for SCO parameters.

}

i i

.r.

,yy E.,

,5-%.-,n.,...,,.,,

.%..,,,..,m.m-,...,,v,,

,-,-.._,%.%,__,,,w--.,,,.,,.,,,

.-,,,y

.wm m.,7

-,_, -, - -. -, - - - - + - -my,m.,,v,-.w-

I 3.3 Revised FSAR Trantient An.alysis In this section those transient analyses in which significant revisions are proposed are highlighted and other revisions are briefly discussed.

l 3.3.1 Increase in Heat Removal by the Secondary System Two transients in this catego which incorporated revisions are Feedwater System Malfunction Caus7ng an increase in Feedwater riow and (

)

Excessive Increase in Secondary Steam Flow.

In both cases revisions are d

minor since the changes are artmarily editorial reflecting methodology l

changes in DPC NE 3000 Rev. 3 anc therefore acceptable.

3.3.2 Decrease in Heat Removal by the Secondary System g

All four transient analyses are affected by revisions in this categoryt (i) turbine trip, (11) loss of offsite power (iii) loss of normal feedwater, and n

(iv) feedwater system pipe break.

Turbine trip is analyzed with respect to g

peak RCS and secondary side pressure, and the others are analyzed with respect to peak RCS pressure and DNB and/or long term core coolability (potential for hot leg boiling).

l 3.3.2.1 Turbine Trin A change in the assumption r7arding the PZR level control is introduced.

OPC stated that the use of th 1evel control in manual with the PZR heaters locked on will be worst in order to elevate the primary pressure to a higher value than is obtained when the PZR level control in automatic.

j l

We concur.

3.3.2.2.

Loss of Offsite Power in addition to the ptential challenges to peak RCS pressure, peak secondary side pressure and DNB, OPC will analyze this transient with respect to long-term core cooling capah111ty.

Therefore, a new section was added to the report describing the analysis to demonstrate that natural circulation can be a

I established after loss of offsite power.

Transient assumptions are reasonable.

With respect to the other transient objectives, changes introduced are benign.

3.3.2.3 Loss of Normal Feedwater

\\

Assumptions regardinf of high SG 1evel is assumedthe initial SG inventory w In the new approach, low insten

, to maximize the secondary pressure.

This is expected to cause an earlier reactor trip on the SG low-low level.

The downward adjustment of the initial SG 1evel introducts l

competing effects with respect to predicted peak primary and secondary pressures and DNBR.

This event is currently not a limiting transient in this category and is bounded b However, y the turbine trip event.

Therefore, its analysis is not required.

OPC stated that analysis may become necessary in the future due to 3

I

hardware or methodology changes.

perfors sensitivity studies with resin that event OPC should be required to ensure conservatise in the analysis. pect to initial condition selections to 3.3.2.4 F- ' tar tvstas piam Break This transient is sigaf ficantly impacted by laplementation of the feedring steam generators, and requires three major assumption changes as a direct result of the design and location of the main feedwater nozzles.

OPC's-discussion of sources of assumption changes and impact of changes in transient results was reviewed and found to be reasonable.

The-loss of offsite power coincident with reactor trip is assumed, resulting

~

in'RCp trip and delay in the startup of the diesel generators for SI.

MSIV closure was determined to be conservative in terms of eariter faulted SGEarly dryout.

Thus, in the revised-assumptions uith turbine trip, which occurs on loss of o,ffsite power.MSIV closure occurs coincident DPC's approach to analysis of this event is acceptable.

3.3.3 Dacreana in Reactor Coolant System Flow Rate Three transients analyzed in this category aret reactor coolant flow, (t) complete loss of forced (1) partial loss of forced (3) reactor coolant pump locked rotor.

reactor coolant flow, and Revisions to both of the corplete and partial loss of forced RC flow are editorial changes and are acceptaM e.

3.3.3.1-RG P - Lachad Rater As stated in Section 3.2, DNgR for this event will be analyzed using the SCD methodology.

values instead of assuring conservative values.Therefore, affected parameters are explanation of the applicability of the SCO methodology for this transientOpc provided and we find the explanation to be acceptable (see also Section 3.2).

OPC stated that cases with had without loss of offsite power coincident with the turbine trip will be analyzed.

As stated in the SER (Ref. 7) for DPC-NE 3002 (Ref. 5), the assumption that IIM of design pressure 11M of design pressure. is not an acceptable limit.

DPC is required to use

_- 3. 3. 4 Reactivity and Power Distribution An==11am DPC added the,possiblitty of reactor trip on high pressurizer pressure in

- addition to the high neutron flux for completeness.

3.3.l' Increanad in Reactor Coolant Inventerv Inadvertent operation of ECCS during at power operation is the only transient 4

l

,i

I analyzud.

Although DNB is a primary e' se.e rn,

since a potential for E

pressurizer overfill exists d.rtng this i. nt OPC added a new section to address that concern for PZR overfill leading to water relief through the PZR 3

Safety Valves (PSVs).

The acceptance :riterian for this analysis is the minimum water relief tec;perature to assure Pr#

arability.

l The SRP suggests use of full power unless a lower power can be justified.

OPC assumes zero power (Ref. 3) lower initial power in this analys,is for conservatism.

This is E

because if overfill occurs at

, then the water relief 5

temperature is more likely to be less than the acceptance criterion.

Therefore DPC selects the initial and boundary conditions in such a way to i

minimize relief temperature.

We find this approach to be reasonable.

3.3.6 Decrease 17. Reactor Coolant Inventory Inadvertent opening of a pressurizer rafety or relief valve and steam generator tube rupture (SGTR) events are the two transients analyzed in this category.

Proposed revisions to the inadvertent opening of a pressurizer safety or relief valve are editorial changes.

3.3.6.1 Steam Generator Tube Ruoture The steam generator tt.be rupture (SGTR) event was not part of the original review since the transient methodology documented in DPC NE 3000 based on the use of the RETRAN computer was approved only for non-LOCA applications. This E

rs striction regarding RETRAN SER (Ref.11)) performance of SGTR analysis with RETRAN (1 tem vil of E

applies to applications which encounter two phase flow in the primary loop, which does occur in maay SGTR scenarios.

In the limited review documented in Reference 12 DPC received approval for an SGTR analysis of the worst ofe,ite dose scenar,io using RETRAN for Catawba Nuclear Station Units 1 and 2.

Justificattan was provided (Ref.13) in a E

qualitative manner by DPC on each of the items cited under restrictions and limitations on the use of RElRAN in its SER.

There is assurance that the use W

of code for that particubr scenario was acceptable since DPC stated that two phase flow was not enantered in the primary loop.

Although NRC approval was specific to Catawba units, as considered in DPC-NE 3000, Catawba and McGuire plants for the purpose of analysis qualification l

are interchangeable.

Therefore DPC stated (Ref. 3) that NRC approval of the SGTR analysis using RETRAN should be applicable to McGuire plant analysis.

We concur with OPC's statement, so long as the scenario is essentially the same and no two-phase flow conditions are encountered in the RCS primary 3

loops.

E The DNBR will be computed using the SCD methodology (see Section 3.2).

l

4.0 CONCLUSION

S Revision 1 to the DPC topical report DPC-NE-3002 and the DPC responses to NRC questions and other supporting documents cited in Section 5.0 were reviewed.

Review of these documents focused upon evaluation of acceptability of the s

I

L h

preposed changes and-the perceived-impact of t.hese changes.

-dilution events were not part of this review.As stated earlier, steam line brea Subject to the foregoing, DK's proposed revision to approach to FSAR Chapter 15 transient analysts, as documented in Revision 1 of DK-NE-3002 and its supporting document, was found to be acceptable subject to the following conditions:

1.

The acceptablitty of -the use of DPC's yproach to FSAR analysis is subject to the conditions of SERs on all aspects of transient analysis and methodologies DPC-NE-2005) as wel(l the SERs on RETRAN and VIPRE computer 2.

There are scenarios in which an SGTR event may result in loss of subcooling and the consequent two phase flow conditions in the primary system.

In s.ch instances, the use of RETRAM is not acceptable without

-a detailed review of the analysis.

3.

transients needs to be reconsidered,In the future if hardware or method and DPC is required to perform sensitivity studies to identify the initial conditions in such a way to avoid conflict primary pressure.between transient objective, such as DN8 and worst 4.

It is. emphasized that, when using the SCO methodology to determine DNBR, the range of applicability of the selected, CHF correlation must not be violated.

5.

criteria for Reactor Coolant Pump Locked Rotor is not acc is required to use 110% of design pressure for that limit.

DPC 5.0 RELMENCE 1.

Letter froc M.S.

Tucker-DPC to USNRC, "FSAR Chapter 15 System

. Transient Anclysis Methodolo(gy, )DPC NE-3002," Revision 1, June 1 2.

" Duke-Power Company The Thermal-Hydraulic Transient Analysis-Methodology - Oconee Nuclear Station, McGuire Nuclear Station. Catawba Nuclear Station," DPC-NE-3000, Revision 3, August 1994.

J 3.

Letter rom M.S. Tuckman (DPC) to USNRC, " Topical Re t'

Chapter 15 System Transient Analysis Methodology" port DPC-3002, "FSAR Responses to NRC

-Questions," August 18, 1995.

I 4.

" Duke Power Company

. The Thermal-Hydraulic Transient Analysis Methodology - Oconee Nuclear Station.- McGuire Nuclear Station, Catawba Nuclear Station," DPC-NE-3000, July 1987.

6 J

5.

"FSAR Chapter 15 System Transient Anklysis Methodology,"

DPC NE-3002, August 1991.

a E.

6.

" Safety Evaluation on Topical Veport OPC-NE-3000, Thermal-Hydraulic Transient Analysis Methodology," Ncvn.;er 15, 1991.

7.

Letter from T.A. Reed (USNRC) to H.B. Tucker (OPC), " Safety Evaluation on Topical Report OPC-NE-3002, "FSAR Chapter 15 System Transient n

Analysis Methodology", " November 15, 1991.

g 8.

" Duke Power Company Multi-dimensional Reactor Transients and Safety Analysis Physics Parameters Methodology,' OPC-NE-3001-P, January 1990.

l 9.

" Technical Evaluation Report on Topical Report OPC-NE-3000 Rev. 3 Thermal-Hydraulic Transient Analysis Methodology,"

ITS/NRC/95-4, 3

September 1995, 3

10.

Letter from G.M. Holahan (USNRC) to H.B. Tucker (OPC), " Acceptance for Referencing of the Modified Licensing Topical Report, OPC-NE-2005P, L

" Thermal-Hydraulic Statistical Core Design Methodology," February 27, 1995.

11.

Letter from C.O. Thomas (USNRC) to T.W. Schnatz (UGRA), " Acceptance for Referencing of Licensing Topical Reports EPRI CCM-5, "RETRAN-A Program for One Dimensional Transient Thermal Hydraulic Analysis of Complex 3

Fluid Flow Systems," and EPRI NP-1850 CCM, "RETRAN-02-A Program for One

[

Dimensional Transient Thermal Hydraulic Analysis of Complex Fluid Flow Systems," September 2, 1984.

12.

Letter from R.E. Martin (NRC) to M.S. Tuckman (DPC), " Safety Evaluation Report for the Catawba Nuclear Station Units 1 and 2, Steam Generator Tube Rupture Analysis," May 14, 1991.

13.

Letter from H.B. Tucker (DPC) to USNRC, " Catawba Nuclear Station Steam Generator Tube Rupture Analysis," December 7, 1987.

I I

I' I

I I

y

h UNITED 8 CATES 8

c-NUCLEAR REGULATORY COMMISSION

• i 1

wAsmwoTow, p. c, sones Novembe-15. 1991 Docket Nos. 50-369, 50-370 50-413 and 50-414 Mr. H. B. Tucker, Senior:Vice President Nuclear Generation

-Duke Power Company P. O. Fox 1007 Charlotte, North Carolina 28201-1007

Dear Mr. Tucker:

SUBiECT: SAFETY EVALUATION 0N TOPICAL REPORT DPC-NE-3002, "FSAR CHAPTER 15 1

-SYSTEtt TRANSIENT ANALYSIS METHODOLOGY," (TAC NO. 66850).

The NFC staff with the support of its contractor' has reviewed Duke Power Company Topical Report DPC-NE-300?, "FSAR Chapter 15 System Transient Analysis

!!ethodology," dated August 30,1991, as supplemented by letters dated October 16 and November 5,1991. The staff has found the topical report to be acceptable subject to the conditions identified in section 4.0 of the attached Technical Evaluation Report as modified by Section 2.? of the attached Safety Evaluation.-

LThis concludes our review activities in response to your submittals regarding Topical Report DPC-NE-3002..

Sincerely.

Timothy A. Reed, Project Manager Project Directorate 11-3 Division of Reactor Projects - I/II

-Office of Nuclear Reactor Regulation

Enclosures:

1. Safety Evaluation P. Technical Evaluation Report cc: See next page

)

% u

s Catawba Nuclear Station Duke Power Company McGuire Nuclear Station cc:

Mr. R. C. Futrell Mr. Alan R. Herdt, Chief 3

Regulatory Compliance Manager Project Branch #3 5

Duke Power Company U.S. Nuclear Regulatory Comission Catawba Nuclear Site 101 Marietta Street, NW, Suite 2900 Clover, South Carolina 29710 Atlanta, Georgia 30323 Mr. A.V. Carr, Esq.

North Carolina Electric Membership Duke Power Company Corp.

l 422 South Church Street P.O. Box 27306 m

Charlotte, North Carolina 28242-0001 Raleigh, North Carolina 27611 J. Michael McGarry, III, Esq.

Saluda River Electric Cooperative, Winston and Strawn

! 'ic.

1400 L Street, N.W.

P.O. Box 929 Washington, DC 20005 Laurens, South Carolina 29360 North Carolina MPA-1 Senior Resident Inspector Suite 600 Route 2 Box 179N g

P.O. Box 29513 York, South Carolina 29745 g

Raleigh, North Carolina 27626-513 Regional Administrator, Region 11 m

Mr. Frank Modrak U.S. Nuclear Regulatory Comission g

Project Manager, Mid-South Area 101 Marietta Street, NW, Suite 2900 ESSD Projects Atlanta, Georgia 30323 Westinghouse Electric Corporation l

MNC West Tower - Bay 241 Pr. Heyward G. Shealy, Chief 5

P.O. Box 355 Bureau of Radiological Health Pittsburgh, Pennsylvania 15230 South Carolina Dept. of Health E

and Environmental Control g

County Panager of York County 2600 Bull Street York County Courthouse Colun.bia, South Carolina 29201 York, South Carolina 29745 Hs Karen E. Long Richard P. Wilson, Esq.

Assistant Attorney General Assistant Attorney General North Caroline Dept. of Justice S.C. Attorney General's Office P.O. Box 629 3

P.O. Box 11549 Raleigh, North Carolina 27602 Columbia, South Carolina 29211 m

Mr. R. L. Gill, Jr.

g Piedmont Municipal Power Agency Licensing 121 Village Drive Duke Power Company Greer, South Carolina 29651 P.O. Box 1007 Charlotte, North Carolina 28201-1007 I

I I

t Catawba Nuclear Station Duke Power Company McGuire Nuclear Station County Manager of Mecklenburg County Dr. John M. Barry 720 East Fourth Street Department of Environmental Health Charlotte, North Carolina 28202 Mecklenburg County 1200 Blythe Boulevard Charlotte, North Carolina 28203 Mr. R. O. Sharpe Mr. Dayne H. Brown, Director Compliance Department of Environmental Health Duke Power Company and Natural Resources McGuire Nuclear Site Division of Radiation Protection 12700 Hagers Ferry Road P. O. Box 27687 Huntersville, North Carolina _ 28078-8985 Raleigh, North Carolina 27611-7687 Senior Resident inspector Mr. M. S. Tuckman c/o U.S. Nuclear Regulatory Commission Vice President Catawba Site 12700 Hagers Ferry Road Duke Power Company Puntersville, North Carolina 28078 P. O. Box 256 Clover, South Carolina 29710 Mr. T. C. McHeekin Vice President, McGuire Site Duke Power Company 12700 llegt.rs Ferry Road Huntersv111e, North Carolina 28078-8985

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( g asop jo,,

UNITED STATES g

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NUCLEAR REGULATORY COMMISSION g

t WASHINGTON, D. C. 20555 e

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3 ENCLOSURE 1 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATING TO TOPICAL REPORT DPC-NE-3002 "FSAR CHAPTER 15 SYSTEM TRANSIENT ANALYSIS METHODOLOGY" DUKE POWER COMPANY MCGUIRE NUCLEAR STATION CATAWBA NUCLEAR STATION DOCKET NOS. 50-369, 50-370, 50-413 AND 50-414 5

1.0 INTRODUCTION

I By letter dated August 30, 1991, the Duke Power Company (DPC) submitted Topical Report DPC-NE-3002, McGuire Nuclear Station and Catawba Nuclear Station, "FSAR Chapter 15 System Transient Analysis Methodology," describing modelling assumption!, used by DPC in performing analyses of FSAR Chapter 15 events. This report, as supplemented by letters of October 16 and November 5, 1991, is intended to augment Topical Report DPC-NE-3000, "The Thermal-Hydraulic g

Transient Analysis Methodology - Oconee Nuclear Station, McGuire Nuclear 5

Station, Catawba Nuclear Station." DPC-NE-3002 is also related to DPC-NE-2004, " Duke Power Company McGuire and Catawba Nuclear Statiuns Core Thermal-Hydraulic Methodology Using VIPRE-01," and DPC-NE-3001,

" Multidimensional Reactor Transients and Safety Analysis Physics Paremeters Methodology."

2.0 STAFF EVALUATION The staff performed its evaluation of the methodology reported in DPC-NE-3002 with the technical assistance of International Technical Services, Inc.

(ITS). The evaluation and findings are described in detail in the ITS technical evaluation report (TER) which is enclosed as part of this report.

As identified in the TER, certain items from DPC-NE-3002 were not included in g

1

2 this review because they have already been included in the review of one of the other related DPC topical reports.

For instance, steam line break, control rod misoperation, and rod ejection events are included in the DPC-NE-3001 review and not repeated herein except as reference.

2.1 Other Items Not Evaluated in TER 2.1.1 Boron Dilution Event The TER identifies that the review of this event is beyond its scope.

DPC-NE-3002 discusses boron dilution events.

However, apart from core physics aspects of DPC-NE-5001, the DPC methodology for evaluating boron dilution events does not use the codes described in the related topical reports identified in Section 1 of this SER. The staff concludes that the finding of acceptability for the boron dilution event analysis methodology of record

-continues to apply.

2.1.2 Steam Generator Tube Rupture (SGTR)

The TER identifies that the review of this event is beyond its scope. DPC-NE-3002 discusses SGTR events; however, except for any parts of DPC-NE-3001 that may be found to apply, the DPC methodology for evaluating SGTRs does not use codes described in the related topical reports identified in Section 1 of this SER.

The staff concludes that the finding of acceptability for the SGTR analysis methodology of record continues to apply.

2.2 TER CONCLUSIONS 2.2.1 Feedwater Line Break TER Section 4.0 (Conclusions) recommends that justifications for trip and actuation times be required when the methodology is applied.

While the staff agrees that trip setpoints and actuation times must be consistent with the assumptions in FSAR analyses, we find that this

I 3

I consistency is implemented in the plant technical specifications and is g

outside the scope of DPC-3002 and this re. view.

5 2.2.2 Power and Reactivity Feedback TER Section 4.0 recomends that the modelling of power and reactivity feedback be reviewed ano that it be assured that such modeiling has no adverse effect on the other modelling described in the TER. The staff review of DPC-NE-3001 covered these considerations and found them acceptable.

2.2.3 Locked Rotor Event TER Section 4.0 identifies that DPC has proposed that reactor coolant system (RCS) pressure of 120% of design pressure be used as a performance acceptance criterion for locked rotor event analyses replacing the previous 110%

criterion. Based on our review we find that the licensee has not provided adequate justification for the proposed change, particularly in light of the credit taken in the DFC methodology for de16yed loss of power to the unlocked reactor coolant pumps. The licensee identifies that its locked rotor event g

analyses calculate a peak RCS pressure of less than 110% design pressure. We 3

find the DPC locked rotor analysis methodology (incorporating the 110% RCS pressure criterion) and results acceptable.

l 2.2.4 Parametric Studies TER Section 4.0 recomends that parameteric studies be r.equired to be presented I

when the metliodology is applied. The licensee has indicated that it will a

perform such studies, as needed. The staff finds this comitment acceptable.

I 3.0 STAFF CONCLUSIONS I

The staff finds the DPC transient analysis methodology acceptable for McGuire and Catawba analyses.

g Date: November 15, 1991 1

ENCLOSURE-2 ITS/NRC/91-10 TECHNICAL EVALUATION OF THE FSAR CHAPTER 15 SYSTEM TRANSIENT ANALYSIS METHODOLOGY IQEJCAL REPORT DPC-NE-3002 FOR THE DUKE POWER COMPANY MCGUIRE AND CATAWBA NUCLEAR STATIONS

1.0 INTRODUCTION

The topical report entitled 'FSAR Chapter 15 System Transient Analysis Methodology," DPC-NE-3002, dated August 1991 (Ref. 1), documents description of modeling assumptions used by Duke Power Company in performing transient analysis of FSAR Chapter 15 accidents by discussing specific choices for use of the models described and qualified in DPC-NE-3000 using the RETRAN and VIPRE-01 computer codes (Refs. 2 and 3).

DPC documented, for licensing application, the conservative nature of (1) the RETRAN model nodalization, (2) RETRAN control systems, (3) use 'of the models j.

described in the DPC-NE-3000 (Ref. 4) and (4) selection of initial and l

boundary conditions.

1.1 Scone of Review Review of the subject topical report focused upon evaluation of acceptability for licensing type analyses, of RETRAN models such as:

(1) ncdalizations for steam generators, core and reactor vessel, including any transient specific modifications; (2) selection of RETRAN interna

• models/ correlations and (3) selection of RETRAN initial and boundary conditions.

The topical report was further reviewed to assure that the application of DPC's DNB methodology was acceptable and consistent with the contents of DPC-NE-2004, DPC-NE-3000 and their supporting documents (Refs. 4 - 8) together 1

1

i h) with their respective TERs (Ref. 9 and 10).

The review, therefore, included identification of which transients DPC intends to analyze using its g'

statistical core design (3C0) methodology and which they do not, and evaluation of DPC's selection of initial and boundary conditions in the systems analysis which was used to determined the statepoints for the DNB analysis.

Although the subject topical report covered all applicable non-LOCA accident in Sections 15.1 through 15.6 of the FSAR, no review was conducted of the details of the transients which are presented in separate topical reports (steam line break, control rod misoperation, rod ejection and steam generator tube rupture) or those accidents identified by the DPC as: (i)notapplicable g'

to M/C plants; (ii) no system analysis deemed necessary; or (iii) those current licensing bases bounded by other analyses.

The following items are beyond the scope of this review: (i) review with respect to the core physics parameters or dose analyses; (ii) review related to the current McGuire 1 Cycle 8 (MIC8) reload analysis submittal; (iii) review of FSAR analyses; (iv) review of the Boron dilution event;(v) review ll of a statically misaligned control rod; and (vi) review of consistency or satisfaction of current Technical Specifications or proposed changes therein.

Therefore, no consistency check was made of DPC's philosophical approach EI documented in the topical report against the MIC8 reload analyses, FSAR analyses or Technical Specification limits.

Furthermore, accuracy of details 5l of the Reactor Protection System, Engineered Safety Features, instrumentation and auxiliary systems and their associated tolerance or uncertainty was not reviewed.

li '

Finally, no technical review was conducted as to the validity of DPC's assumption of 120% of design pressure as an acceptance criterion for the RCP locked rotor analysis.

7.0

SUMMARY

Topical Report DPC-NE-3002 documen'ts DPC's approach to performance of the ll 2

1

.NSSS primary and secondary system analyses of FSAR Chapter 15 accidents.

It covers all applicable non-LOCA accidents in Sections 15.1 through 15.6 of the FSAR except steam line break, dropped rod, and rod ejection, which are addressed in a separate topical report, DPC NE-3001 (Ref.11).

DPC NE-3002 presents brief discussion-of specific choices-for the use of the RETRAN plant models described in DPC-NE-3000, including nodalization.. initial and ' boundary conditions and modeling of the process-instrumentation and control systems.

Also presented are assumptions related to the Reactor Protection System, the Engineered Safety Features Actuation System, and availability of other systems and components. Trip actuation is discussed in

. generality, and thus potential -trip functions are presented.

However, the-report contains no justification for actuation times for reactor trip, safety

-injection and other actions.

Assumptions related to reactivity feedback modeling, power peaking and power distribution are not presented, therefore are not reviewed.

Furthermore, although there is mention of intent to

. perform (or, in some instances, actual _ performance of). parametric studies to identify conservative scenarios and assumptions, none of such studies were presented.

The topical report contains qualitative, rather than quantitative information, and no the actual RETRAN or VIPRE computed results are presented.- Therefore, this report presents DPC's philosophical approaches to performance of FSAR Chapter 15 type analysis.

Nodalization selection is made based upon symmetry or a degree of asymmetry of the expected transient system response. Selection of initial and boundary conditions-is designed to result in~ conservative predictions with respect-to the aspect'of a transient which the analysis is intended to assess, such as peak primary pressure, peak secondary pressure, short and long tenn core coolability.

With respect to core coolability, selection of initial conditions depends upon the mode of DNBR computation; i.e.,. the use of the DPC developed SCD methodology SCD or the traditional DNBR methodology.

3

I 3.0 EVALUATION Acceptability of DPC's application of RETRAN models and assumptions for thermal-hydraulic calculations of FSAR Chapter 15 transient analysis of its McGuire/Catwba (M/C) plants is discussed below.

In addition, application to licensing type transient analysis of the SCD methodology described in DPC g

Topical Report DPC-NE-2004 and its supplements was also reviewed.

E 3.1 BGuire and Catawba RETRAN Plant Model The RETRAN base models for M/C plants were qualified in DPC-NE-3000 for both best-estimate and licensing type applications, subject to limitations described in the TER (Ref. 10).

DPC developed three different size models of the M/C Plants: a one-loop plant model to be used when all four loops are expected to behave similarly so that there is no asymmetric condition; and a two-loop and a three-loop model to be used when more detail is desirable due to asymmetric conditions expected in the reactor coolant system during the transient.

The steam generator model was examined in detail during review of DPC-NE-3000 for use in licensing analyses, specifically in over-pressurization g

transients.

That review focused upon the ability of the DPC SG model to 5

predict SG tube uncovery and resulting degradation of primary-to-secondary heat transfer.

DPC presented results from an extensive sensitivity study to assure that during two transients considered, loss of normal feedwater and Edwater line break, the current modeling is adequate.

The finding of that review is documented in the TER for DPC-NE-3000 and imposes certain g

limitations on use.

Use of certain RETRAN internal models such as the inter-region heat transfer model and local condition heat transfer model was reviewed and found to be acceptable for use in the components and for transients identified by DPC (Ref. 8).

4 I

I

S 3.2 1CD Transients The core thermal-hydraulics for most of the transients considered in this topical report is analyzed using the DPC deYaloped SCD methodology.

For these transients, certain initial conditions used in the transient safety analysis are selected to be at nominal conditions, as qualitatively defined in Reference 10, since the uncertainty associated with the initial conditions is accounted for in the SCD method.

These parameters are: (1) power level, (2} Core flow (RCS flowrate and core bypass flow), (3) Coolant temperature, and (4) RCS pressure.

Other parameters necessary for the SCD method are not discussed in this topical report.

Those transient for which DNB is relevant but for which the SCD is not used are; (1) turbine trip. (2) RCP Locked Rotor, (3) startup of an inactive reactor coolant pump at an incorrect temperature, and (4) steam line break.

The-turbine trip is not analyzed because as postulated, this transient results in a monotonically increasing DNBR which therefore is act an issue.

The SCD method is not used for DNBR analysis of steam line break since the primary pressure predicted during the transient is below the range of l

applicability of the CHF correlation used to develop the response surface l

equation.

Similarly, the other events are outside the range of applicability of-the response surface equation, t

3.3 Transient Initial Conditio^s and Assumotions In this section, initial and boundary conditions such as the transient initiators, reactor coolant pump operation ' ind assumptions related to safety and relief valves are-discussed.

Control, protection and safeguard system modeling is discussed highlighting which systems are credited or not credited, actuation logic and modeling assumptions.

A summary of assumptions and conditions selected by DPC is shown in Table 8.1 of the topical report as corrected by Reference 8.

Definition of the terms used in the table are provided in Reference 8.

5

I I

Deviations from the following comon analytical approach are highlighted in the ensuing sections of this TER:

1.

For DNB analysis of SCD transients, SCD parameters are set at nominal while non-SCD parameters are set at conservative values.

2.

For DNB analysis of non-SCD transients, all key parameters were set at conservative values.

3.

For all DNB analyses except those which were initiated by reactivity insertion, the gap conductivity is assumed to be low to maximize the ste ed energy in the fuel and thereby minimize the change in heat flux l

out of the fuel during the transient, whereas for the reactivity insertion driven transients, the gap conductivity is assumed to be high because the transient duration is short compared to the fuel's thermal constant.

For DNB analysis of transients which depressurize the primary, the pressurizer level is assumed to be at its high limit to g

maximize the depressurization.

5 4.

Where transients are being analyzed for peak RCS pressure, the primary-to-secondary heat transfer is minimized, the pressurizer is assumed to be initially at the high limit of its operating range to produce the maximum pressure as the vapor region is compressed, and the fuel is assumed to have a high gap conductivity (which is accompanied by a low average fuel temperature) to maximize the energy transferred into the primary fluid.

E 5.

For transients initiated on the primary side which have chort duration, it is assumed that the results are insensitive to modeling of the secondary side and primary-to-secondary heat transfer.

Therefore, for all such analyses the secondary side and steam generator parameters were set at nominal rather than conservative conditions.

6.

Transients with symmetric loop behavior are analyzed with a single loop I

I

plant model while asymmetric transients are analyzed with a two loop model.

7.

DPC uses the setpoint values and response time of trip function as specified in the Technical Specifications and accounts for uncertainty.

8.

Decay heat is computed using the end-of-cycle data based upon ANSI /ANS-5.1-1979 standards plus a two sigma uncertainty.

9.

Availability assumptions on the PZR pressure and level control mechanisms, such as the PZR sprays, PORVs and heaters, and the modes of operation are made in various combination to yield system behavior consistent with the transient being modeled.

Steam line PORVs and condenser dump modeling is similar.

3.3.1 Increase in Heat Removal by the Secondary System Four transients are considered in this category; (1) feedwater (FW) system malfunctions that result in a reduction in feedwater tems,erature, (2) feedwater system malfunction causing an increase in feedwater flow, (3) excessive increase in secondary steam flow, and (4) inadvertent opening of a steam generator relief or safety valve.

As stated earlier review of the steam line break event is beyond of the scope of this review.

The F4 temperature reduction event is bounded by the FW flow increase event, which is analyzed.

Since inadvertent opening of a SG relief or safety valve is similar to, and bounded by, the steam line break, it is not analyzed, however a small step increase eqd to 10% of licensed core thermal power is presented in the report.

Both of these transients are analyzed with respect to DNB using the SCD method.

An additional condition to consider a FW malfunction affecting more than one loop was recently added to the scenario of FW system malfunction event. DPC felt that the most limiting case would involve multi-loop malfunction affecting all loops equally.

Therefore, the use of a single-loop model is 7

I appropriato.

The pressurizer liquid level is assumed to be high to maximize the primary pressure decrease.

The SG mixture level is assumed to be low for the feedwater flow increase malfunction in order to maximize the overcooling l

before a protection or safeguards actuation.

The small step increase in the steam flow event is not considered to be sensitive to SG level.

A conservatively large step change in main feedwater flow is assumed for the g

FW malfunction event.

A 10% step increase in steam flow is assumed for the W

other event.

l In both event analyses, two cases are investigated to assess whether modeling the rod control system in manual control or automatic control would result in g

the worst case.

In addition, minimum AFW flow, turbine trip and FW isolation are credited and expected to trip on SG narrow range level after the g

appropriate Technical Specification response time delay.

W The input selection and transient assumptions as described in the topical report for this category of events is acceptable.

3.3.2 Decrease in Heat Removal by the Secondary System Four transient analyses are performed in this category: (1) turbine trip, (2) loss of offsite power, (3) loss of normal feedwater, and (4) feedwater system pipe break.

Turbine trip is analyzed with respect to peak RCS and secondary side pressure, and the others are analyzed with respect to peak RCS pressure and DNB and/or long term corc coolability (r ential for hot leg boiling).

3.3.2.1 Turbine Trio DNBR analysis is not performed for this transient since this is a rapid transient in which prior to reactor trip, a significant RCS pressurization takes place due to the reduction in secondary heat sink offsetting the B

increase in core inlet temperature, while the core power and the core flow E

I

change very little.

Therefore this event does not challenge the DNBR safety margin.

In peak RCS pressure analysis, reactor trip is expected to actuate on either overtemperature delta T (OTDT), overpower delta T (OPDT), or PZR high pressure.

MFW is isolated upon turbine trip.

In the peak SG secondary side pressure analysis, RCS flow is assumed to be high to maximize the primary-to-secondary heat transfer.-

High SG 1evel is assumed, to maximize the secondary pressure.

In order to prevent a high PZR pressure reactor trip prior to OTDT trip, PZR PORVs are assumed operable.

3.3.2.2.

Loss of Offsite Power This transient has potential challences to peak RCS pressure, peak secondary side pressure, and DNB.

However, & DNBR results from this event are bounded by the loss of flow event becautu these two events, as postulated by DPC, differ only in the timing of the insertion of the control rods.

In the loss of offsite power (LOOP) event, the rods begin to fall immediately, whereas in the loss of flow event rods fall after an instrumentation delay.

Similarly, the peak primary system pressure is bounded by the loss of flow evat.

The secondary s ide pressure

'.s bounded by the turbine trip event, for LOOP, the reactor trips prior to the turbine trip, therefore by the time the secondary pressure begins to increase, the primary system is rapidly cooling down.

However, in the turbine trip event, reactor trip is.after the turbine trip.

Therefore, a quantitative analysis of this transiert is not required.

Nevertheless, DPC provided the analytical methodology for analysis of this event should it become necessary.

The transient will be analyzed with respect to three different objectives:

peak RCS pressure; peak secondary side pressure: and DNB using the SCD method.

9

I For peak RCS pressure analysis, all RCPs are tripped as the transient initiating event.

Reactor trip and MFW trip are assumed on LOOP.

'"W is assumed to actuate on LOOP after a delay.

However, in order to minimize the heat removal capability, the minimum AFW flow is assumed.

For peak SG tecondary side pressure analysis, DPC assumes high RCS flow to maxi'nize the primary-to-secondary heat transfer.

High SG level is assumed, g

to maximize the secondary pressure.

In order to determine statepoints to be used in DNB analysis using the SCD method, PZR level is assumed to be low to minimize the primary pressure increase.

Low SG 1evel is assumed, which minimizes primary-to-secondary heat transfer.

3.3.2.3 Loss of Normal Feedwater The loss of normal feedwater is bounded by the turbine trip transient.

The power to heat sink mismatch is greater for the turbine trip because the reactor trip and turbine trip occur simultaneously for the loss of FW event, while for the turbine trip event, reactor trip occurs after the turbine trip.

I Therefore, a quantitative analysis of this transient is not required.

Nevertheless, DPC provided the analytical methodology for analysis of this event shculd it become necessary.

For peak RCS pressure analysis, reactor trip is assumed on the SG low-low level.

AFW is assumed to actuate on the SG low-low level; however, in order to minimize the heat removal capability, the minimum AFW flow is asumed.

In order to maximize the peak SG secondary side pressure by maximizing the l

prin.ary-to-secondary heat transfer, high RCS flow is assumed.

High SG level is assumed, to maximize the secondary pressure.

Reactor trip is assumed on the SG low-low level.

AFW is assumed to actuated on the SG low-low level with a minimum flow delivery.

10 I

In order to determine statepoints to be used in DNB analysis using the SCD method,- PZR level is assumed to be low to minimize the primary pressure increase.

High SG 1evel is assumed to delay reactor trip on SG low-low level.

Reactor trip is assumed on the SG low-low level.

AFW is assumed to actuate on SG low-low level with a minimum flow delivery.

Turbine trip is assumed on reactor trip.

i 3.3.2.4

-Feedwater System Pine Break This transient is analyzed with respect to (1) DNB using the SCD method, and (2) long term core coolability (potential for boiling in the hot leg).

The most limiting event assumed by DPC is the double-ended rupture of the largest feedwater line.

The DNB analysis for this transient is analyzed as a complete loss of coolant flow event initiated from an off normal conditions.

It is postulated in this transient that coincident with reactor trip (and turbine trip) loss of offsite power is assumed to occur causing RCP coastdown.

Reactor trip is assumed on the OTDT.

AFW is assumed to actuate on SG low-low level after a delay with a minimum flow delivery in order to minimize the heat removal capability. Turbine trip is assumed on reactor trip.

Long Term Core Coolability (Hot Leg Boiling)

A three-loop model is used since uneven flow of AFW into the unaffected SGs causes asymmetric loop behavior.

High core power is assumed to maximize the heat flux.

PZR pressure '

assumed to be low, which minimizes the margin to hot leg boiling by lowering the hot leg saturation temperature.

A high RCS temperature is assumed, to increase the amount of energy to be removed.

Low SG level is assumed to maximize the loss of secondary heat sink.

A high fuel temperature is assumed, accompanied by low gap conductivity.

High SG tube plugging is assumed to minimize the primary-to-secondary heat transfer.

11

The RCPs are assumed to trip at 15 seconds, which is assumed to precede the time at which the pumps would be manually tripped on high-high containment pressure.

Reactor trip is assumed at 10 seconds into the transient which is after the l

SI actuation on high containment pressure.

SI actuation is assumed on high containment pressure at 10 seconds and terminated at 70 seconds when the emergency procedure criteria for termination are assumed to be met.

AFW is assumed to actuate on SI actuation after a delay.

However, in order to minimize the heat removal capability, the minimum AFW flow is assumed.

AFW is terminated at 120 seconds into the transient.

MSIV closure are actuated at 15 seconds and assumed to precede automatic closure on high-high containment pressure.

Early closure is conservative in order to initiate the g

overheating portion of the transient.

However, no justification was presented for any of the actuation time assumptions.

The input selection and transient assumptions as described in the topical report for this category of events i., acceptable; however, trip actuation times must be justified in any application of this methodology.

3.3.3 Decrease in Reactor coolant System Flow Rate Three transient analyzed in this category are: (1) partial loss of forced reactor coolant flow, (2) complete loss of forced reactor coolant flow and (3) reactor coolant pump locked rotor.

3.3.3.1 Loss of Forced RC Flow: Partial and Comolete I

Due to the similarity of these events, the partial loss of forced flow and complete loss of forced flow events are discussed together.

A single-loop model is used for analysis of the complete loss of forced flow since the transient impacts all loops symmetrically: the two-loop model is used for the partial loss of forced flow event analysis.

In both cases, DNB g

analysis will be performed using the SCD method.

E 12 I

For the partial loss of flow, a single reat. tor coolant pump is assumed to trip, while the other three pumps remain operational for the duration of the transient.

For the complete loss of forced flow, all four RCPs are tripped at the initiation of the transient. The ru.np medel is adjusted to yield pump coastdown which is conservative with respect to the flow coastdown test data.

Reactor trip for the partial loss event is assumed on low RCS flow after an appropriate delay time, while for the complete loss event, reactor trip is assumed on RCP undervoltage. Turbine trip is assumed on reactor trip.

3.3.3.2 RC Pumo Locked Rotor This transient is analyzed with respect to both peak RCS pressure and DNB.

For both analyses a two-loop model is used for analysis due to the asymmetric C

nature of the transient.

In presenting its approach to these transients, DPC stattd that it used an acceptance criterion of 120% design pressure.

Review of this criterion is beyond the scope of this review.

In order to maximize RCS pressure, the RCS flow is assumed at its low initial flow to minimize the heat transfer to the secondary side.

A high core bypass flow is assumed to minimize the core flow to maximize the heat-up.

The initial RCS average temperature is also assumed at its high level.

The transient initiating event is seizure of the rotor of the RCP in the faulted loop, while the other three pumps trip on bus undervoltage following the loss of offsite power.

Offsite power is assumed to be lost coincident with the turbine trip.

Reactor trip is assumed on low RCS flow in the affected loop. Turbine trip is assumed on reactor trip.

DNB analysis is performed using the traditional method.

Therefore, core power is assumed to be high, while the PZR pressure and level are assumed to be low to minimize the pressure increase.

High initial loop average 13

I temperature is assumed to maximize the stored energy in the primary which must be removed.

Similarly, a high core bypass flow resulting in low core l

flow is assumed to maximize the heat-up and low RCS flow is chosen to maximize the primary-to-secondary heat transfer.

Offsite power is assumed to be lost coincident with the turbine trip.

Similar to the peak RCS pressure case, reactor trip is assumed on low RCS g

flow in the affected loop. Turbine trip is assumed on reactor trip.

5 The input selection and transient assumptions as described in the topical report for this category of events is acceptable; however, the assumption that 120% of design pressure is an acceptable limit must be reviewed by the l

NRC staff.

3.3.4 Reactivity and Power Distribution Anomalies l

Seven transients are considered in this category; (1) uncontrolled bank withdra.wal from a

suberitical or low power startup condition.

(2) uncontrolled bank withdrawal at power, (3) statically misaligned control rod l

(4) single control rod withdrawal, (5) startup of an inactive reactor coolant pump at an incorrect temperature, (6) CVCS malfunction (boron dilution), and (7) inadvertent loading and operation of a fuel assembly in an improper position.

Review of boron dilution event analysis and of inadvertent loading and l

operation of a fuel assembly in an improper position is beyond the scope of this review.

Acceptability of these events should be reviewed by an appropriate branch of NRC.

l Each of the two uncontrolled bank withdrawal events is analyzed with respect to both peak RCS pressure and DNB.

The single control rod withdrawal and startup of an inactive RCP at in incorrect temperature are analyzed for DNB g

only.

All transients except the startup of an inactive RCP are SCD W

transients.

I_

14 I

I!

l

3.3.4.1 Uncontrolled Bank Withdrawal from a Suberitical or low Power The cora power is assumed at a critical zero power startup condition.

Peak RCS pressure analysis is performed assuming the RCPs are operational to minimize thermal feedback during the power excursion.

Reactor trip is assumed on high power range flux trip.

DNB analysis will be performed using the SCD method except when the potential for bottom-peaked power distributions exists.

In such event, since SCD is not applicable, DNBR analysis is performed using the W-35 CHF correlation in the traditional manner accounting for uncertainties explicitly.

Thus the input selection criteria described below is only applicable when the SCD method is used.

In order to determine the statepoints to be used in the DNB analysis, the initial conditions for the SCD treated parameters for the cases are set at nominal conditions for this power with three RCPs in operation.

To minimize the PZR pressure increase, low initial PZR pressure and level is assumed.

Three RCPs, a minimum number required for the modes of operation applicable for this transient, are assumed operational to yield low flow.

Reactor trip is assumed on high power range flux trip.

3.3.4.2 Uncontrolled Bank Withdrawal from Power For peak RCS pressure analysis, in order to avoid trip on high flux, the transient is initiated from low power.

The SG 1evel is assumed high and a high amount of SG tube plugging is assumed in order to minimize primary-to-secondary heat transfer.

In order to determine statepoints to be used in DNB analysis using the SCD method, the initial conditions for the SCD treated parameters for the cases are set at the nominal conditions corresponding to each of the power levels, which span the full spectrum, for which this event is analyzed.

The steam 15 I

I I

generator level is assumed to be high in an effort to minimize the primary-to-secondary heat transfer.

Analysis is performed with and without PZR sprays and PORVs.

l 3.3.4.3 Control Rod Misooeration Transient systems analysis is not performed for the statically misaligned g

control rod event.

Steady-state three-dimensional power peaking analyses are performed to assure that the resulting asymmetric power distribution will not g

result in DNB.

W 3.3.4.4 Sinale Rod Withdrawal DNB analysis will be performed using the SCD method.

l The SG mixture level is assumed high to maximize the secondary pressure and minimize the primary-to-secondary heat transfer.

High SG tube plugging is assumed to minimize the primary-to secondary h6at transfer.

I Reactor trip is assumed on one of four functions; OTDT, OPDT, PZR high pressure and power range high flux.

In order to delay reactor trip on high PZR pressure, the PZR heaters is assumed to be in manual.

Similarly the PORVs are assumed disabled in order to delay reactor trip on OTDT and high g

PZR pressure.

Feedwater control is in automatic to prevent SG 1evel trip.

AFW is assumed disabled. Turbine trip is assumed on reactor trip.

3.3.4.5 Startuo of an Inactive RCP at an Incorrect Temoerature I

DNB analysis will be performed using the traditional method.

A two-loop model will be used because of the loop asymmetry.

l The initial indicated power level is set to delay or prevent reactor trip from a low flow trip setpoint. The core bypass flow is assumed to be high to minimize the core flow to maximize the heatup.

Similarly the RCS flow in the three unaffected loop is the minimum flow allowed by Technical Specification.

16 I

The'three -unaffected RCPs are modeled assuming a constant speed through the transient.

The i.JP that-is initially inactive is modeled with a conservative speed vs. time controller.

i The SG level control is assumed to be in automatic mode to minimize the probability of trip on low-low SG level.

Turbine trip is assumed to_ be in manual.

The input selection and -transient assumptions as dea ribed in the topical report for this category of events is acceptable.

3.3.5

-Increased in-Reactor Coolant Inventory Inadvertent operation of ECCS during power operation is the only transient analyzed.. _ The DNS results of this-transient are bounded by the inadvertent opening of a PZR safety or relief valve transient.

Notwithstanding the qualitative argument -provided by DPC for not analyzing

-i

.this event, DPC nevertheless presented the analytical methodology _ used for this analysis, should reanalysis-become necessary in the future.

DNB analysis will be performed using the SCD method.

.A maximum safety injection flowrate with a conservatively high. boron concentration is assumed to yield the most limiting transient response because-it minimizes power and thereby maximizes the amount of ECCS which can be-injected.

In order to minimize the delay in the delivery of the borated water, no credit is assumed for the purge volume of unborated water in the injection line.,

Reactor trip is assumed on low PZR pressure aqer an appropriate delay time.

The steam line PORVs and condenser _ steam dump are assumed to be unavailable to n.aximize secondary side pressurization and minimize the primsry-to-secondary heat transfer, also tending to maximize primary fluid volume.

17 I

I Turbine trip is assumed on reactor trip.

The input selection and transient assumptions as described in the topical l

report for this category of events is acceptable.

3.3.6 Decrease in Reactor Coolant Inventory Inadvertent opening of a pressurizer safety or relief valve and steam generator tube rupture events are the two transients analyzed in this category. The steam generator tube rupture event is *;eyond the scope of this review.

Therefore, the inadvertent opening of a PZR safety or relief valve l

was reviewed.

In order to determine statepoints to be used in DNB analysis using the SCD method, the pressurizer liquid level is assumed to be high to maximize the primary pressure decrease, which maximizes the added coolant inventory.

g Reactor trip is credited.

The turbine trip is assumed on reactor trip 5

without delay to minimize post-trip primary-to-secondary heat removal.

I The input selection and transkt assumptions as described in the topical report for this c:itegory of events is acceptable.

4.0 CONCLUSION

S DPC topical report DPC-NE-3002 and its supporting documents, including the DPC responses to questions, were reviewed.

Review of the subject tegical report focused upon evaluation of acceptability of the RETRAN models for the type of analysis generally described on the subject topical report.

The topical report was further reviewed to assure g

that the application of the DPC's DNB methodology was consistent with the contents of DPC-NE-2004 and DPC-NE-3000 and acceptable.

"he review, g

threfore, included identification of the SCD transients and evaluation of 5

EPC's selected initial and boundary conditions in the systems analysis which Wds used to determined the statepoints for the DNB analysis.

18 I

Il

As - stated earlier, steam line break,_ rod ejection, dropped rod, steam generator tube rupture and boron dilution events were not part of this review (see also Section 1.1).

Tubject to the foregoing, DPC's approach to FSAR Chapter 15 transient analysis.- as documented in - DPC NE-3002 and its supporting documents, was generally found to be acceptable subject to the following conditions:

1.

.DPC's Statistical Core Design methodology treat seven state variables as key parameters.

Four of these variables were accounted for in this topical report. Of the remaining parameters, the power factors are also input items for systems analysis, which was not presented in the topical report.

Similarly, reactivity feedback was not discussed in this report.

Both of these parameters can significantly influence the course of the transient.

Therefore, when application of the philosophical approach reported in this topical report is made and submitted for NRC review and approval, review should be made of the modeling of power and

(

reactivity feedback, and to assure that such modeling has no adverse impact on the other modeling described herein.

2.

Validity of-DPC's assumption of 1207, of design pressure as part of the acceptance criteria for Reactor Coolant Pump Locked Rotor should be determined by the NRC staff.

3.

No justification was presented for trip and actuation times assumed in the Feedwater System Pipe Break event analysis.

Such justifications must be presented when this m(thodology is applied.

4.

DPC documented intent to perform parametric studies in order to select conservative scenarios or assumptions throughout the subject topical report.

Ther isre, such parametric studies must be presented when this methodology is applied.

19

Il

5.0 REFERENCES

(Amended to reflect transmittal dates) 1.

Letter,M.S.Tuckman(DPC)toNRC,"FSARChapter15SystemTransient Analysis Methodology," DPC-NE-3002, August 30, 1991.

Letter, C. O. Thomas (NRC) to T. W. Schnatz (UGRA)). September A,1984, 2.

(Transmittal of RETRAN-02 Safety Evaluation Report 3.

Letter, C. E. Rossi (NRC) to J. A. Blaisdell (UGRA), May 1, 1986, E'

(Transmittal of VIPRE-01 Safety Evaluation Report).

E i

4.

Letter. H. B. Tucker (DPC) to NRC, " Thermal-Hydraulic Transient Analysis a'

Methodology," DPC-NE-3000, September 29, 1987.

g 5.

Letter, H. B. Tucker (DPC) to NRC, " Duke Pwer Company McGuire and Catawba li Nuclear Stations Core Thermal-Hydrauli:: Methodology Using VIPRE-01,"

DPC-NE-2004, January 9,1989.

6.

Letter,ll. S. Tuckman (DPC) to flRC, "Supp1 mental Infcrmation to Assist 3l in Review of Topical Reports DPC-NE-3000 and DPC-NE-2004," August 29, 1991.

gj l

7.

Letter, H. B. Tucker (DPC) to NRC, " Handouts Presented in the October 7 8 8, li 1991 !!eeting with NRC Staff and Contract Reviewers," October 16, 1991.

8.

Letter, H. B. Tucker (DPC) to flRC, " Final Response to Questions Regarding the Topical Reports Associated with the MIC8 Reload Package," tiovember 5, E

1991.

E !

9.

Letter, T. A. Reed (NRC) to H. B. Tucker (DPC), Safety Evaluation on g~,

l Topical Report DPC-NE-2004, " Core Thermal-Hydraulic Methodology Using g'

VIPEE-01," November 15, 1991.

10. Letter, T. A. Reed (NRC) to DPC, Safety Evaluation on Topical Report ll DPC-NE-3000,

• Thermal-Hydraulic Transient Analysis T.ethodology," November 15, 1991.

11. Letter, T. A. Reed (NRC) to H. B. Tucker (Dic), Safety Evaluation on Topical Peport DPC-NE-3001, " Multidimensional Reactor Transients and Safety Analysis Physics Parameters Methodology," November 15, 1991.

I I

20 Il

f-l Duke Power Company McGuire Nuclear Station Catawba Nuclear Station UFSAR Chapter 15 System Transient Analysis Methodology DPC.NE4002.A Revision 2 December 1997 c.

(

' Nuclear Engineering Division Nuclear Generation Department Duke Power Coi..pany F

l l:-

Abstract This report documents the conservative medeling assumptions used by Duke Power Company in performing the NSSS primary and secondary system analyses of UFSAR Chapter 15 accidents.

It covers a33 applicable non-LOCA accidents in Sections 15.1 through.95.** e the UFSAR except those already addressed in Duke Power Company topir.& report DPC-NE-3001.

The areas discussed are nodalization, initial condit4ons, boundary conditions, modeling cf the process instrumentetion and control syatems, the Reactor Protection System, the Engineer 4bd Safety Features Actuation System, and availability of other important systems and components.

i

i UFSAR CHAPTER 15 SYSTEM TRANSIENT ANALYSIS METHODOLOGY Table of Contente

1.0 INTRODUCTION

2.0 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 2.1 Feedwater Evatem Malfunctions That Result f_n A Reduction in Feedwater Tomnerature 2.2 Feedwater Evstem Malfunction causino an increase in Egedwater Flow 2.2.1 Hodalization 2.2.2 Initial Conditions 2.2.3 Boundary Conditions 2.2.4 Control, Protection, and Safeguards Systens Modeling 2.3 Excessive increase in Secondarv Steam Flog 2.3.1 Nodalization 2.3.2 Init4a1 Conditions 2.3.3 Boundary Conditions 2.3.4 Control, Protection, and Safeguards Systems Modeling 2.4 Inadvertent Onenina of a Steam Generator Relief or Enfetv Valve 3.0 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 3.1 Turbine Trio 3.1.1 Peak ACS Preature.'.nalysis 3.1.1.1 Nodalization 3.1.1.2

. Initial conditions 3.1.1.3 Boundary conditions 3.1.1.4 Control, Protection, and Safeguards System Modeling 3.1.2 Peak Main Steam System Pressure Analysis 3.1.2.1 Nodalization 3.1.2.2 Iritial conditions 3.1.2.3 Joandary conditions 3.1.2.4 Control, Protection, and Safeguards System Modeling 3.2-Loss of Non-Pmeroency AC Power To The Station 3.2.1 Peak RCS Pressure Analysis 3.2.1.1 Nodalization 3.2.1.2 Initial Conditions 3.2.1.3 Boundary Conditions 3.2.1.4 Control, Protection, and Safeguards System Modeling 3.2.2 Peak Main Steam System Pressure Analysis 3.2.2.1 Nodalization 3.2.2.2 Initial Conditions 3.2.2.3 Boundary conditions 3.2.2.4 Control, Protection, and Safeguards System Modeling 3.2.3 Core Cooling Capability Analysis - Short Term 3.2.3.1 Nodalization 3 2.3.2 Initial Conditions 11

I 3.2.3.3 Boundary conditions 3.2.3.4 control, Protection, and Safeguards System Modeling 3.2.4 Core Cooling Capability Analysis - Long Term 3.2.4.1 Nodalization 3.2.4.2 Initial Conditions 3.2.4.3 Boundary Conditione 3.2.4.4 Control, Protection, and Safeguards System Modeling 3.3 Losn Of flormal FeedwgLgI 3.3.1 Peak RCS Pressure Analysis 3.3.1.1 Nodalization 3.3.1.2 Initial Conditions 3.3.1.3 Boundary Conditions 3.3.1.4 control, Protection, and Safeguards System Modeling 3.3.2 Peak Main Steam System Pressure Analysis 3.3.2.1 Nodalization 3.3.2.2 Initial Conditions 3.3.2.3 Boundary Conditions 3.3.2.4 control, Protection, and Safeguards System Modeling 3.3.3 Core Cooling Capability Analysis 3.3.3.1 Nodalization 3.3.3.2 Initial Conditions 3.3.3.3 Boundary Conditions

)

3.3.3.4 Control, Protection, and Safeguarda System Modeling

)

3.4 7.,eedwater System Pine Break W

3.4.1 Short Term Core Cooling Capability 3.4.1.1 Nodalization 3.4.1.2 Initial Conditions 3.4.1.3 B'.undary Conditions 3.4.1.4 Control, Protection, and Safeguards System Mode 3.4.2 Long Term core Cooling capability 3.4.2.1 Nodalization 3.4.2.2 Initial Conditions 3.4.2.3 Boundary Conditions 3.4.2.4 Control, Protection, and Safeguards System Modeling 4.0 DECREASE IN REACTOR COOLANT SYSTEM FLOW RATE 4.1 Partial Loss of Forced Reactor coolant Plow 4.1.1 Nodalization 4.1.2 Initial Conditions 4.1.3 Boundary Conditions 4.1.4 Control, Protection, and Safeguards System Modeling 4.2 comniete Loss Of Forced Reactor coolant Flow 4.2.1 Nodalization 4.2.2 Initial Conditions 4.2.3 Boundary Conditions l

4.2.4 Control, Protection, and Sefeguards System Modeling g

4.3 Reactor coolant Pumn Locke. Rotor 4.3.1 Peak RCS Pressure Analysis 4.3.1.1 Nodalization 4.3.1.2 Initial Conditions 4.3.1.3 Boundary conditions lii I

i 4.3.1.4 Control, Protection, and Safeguards System Modeling 4.3.2 Core Cooling Capability Analysis I

4.3.2.1 Nodalization 4.3.2.2 Initial Conditions 4.3.2.3 Boundary conditions 4.3.2.4 Control, Protection, and Safeguards System Modeling 4.3.2.5 other Assumptions 5.0 REACTIVITY AND POWER DISTRIBUTION ANOMALIES 5.1 Uncontrolled Bank Withdrawal From a suberltical or Low Poweg 5.1.1 Peak RCS Pressure Analysis 5.1.1.1 Nodalization 5.1.1.2 Initial conditions 5.1.1.3 Boundary Conditions 5.1.1.4 Control, Protection, and Safeauards System Modeling 5.1.2 Core Cooling Capability Analysis 5.1.2.1 Nodalitation 5.1.2.2 Initial Conditions 5.1.2.3 Boundary Conditions 5.1.2.4 Control, Protection, and Safeguards Syr*a:m Modeling 5.1.2.5 Other Assumptions a

5.2 Uncontrolled Bank Withdrawal at Power 5.2.1 Peak RCS Pressure Analysis 5.2.1.1 Nodalization 5.2.1.2 Initial Conditions 5.2.1.3 Boundary Conditions 5.2.1.4 control, Protection, and Safeguards System Modeling 5.2.2 Core Cooling Capability Analysis 5.2.2.1 Noda11:ation 5.2.2.2 Initial Conditions 5.2.2.3 Boundary Conditions 5.2.2.4 Control, Protection, and Safeguards System Modeling 5.3 control Rod Mimoneration (Statica11v Mimalioned Pod) 5.4 control Rod Minoceration (Sinale Rod Withdrawall 5.4.1 Nodalization 5.4.2 Initial Conditions 5.4.3 Boundary Conditions j

5.4.4 Control, Protection, and Safeguards System Modeling 5.5 startun of An Inactive neactor coolant Pumn At An Incorrect Temnerature 5.5.1 Nodalization 5.5.2 Initial Conditions 5.5.3 Boundary conditicns 5.5.4 Control, Protection, and Safeguards Systems Modeling 5.6 CVCS Malfunction That Results In A Decrease In Boron concentration In The Reactor coolant 5.6.1 Initial Conditions 5.6.2 Boundary Conditions 5.6.3 control, Protection, and Safeguards System Modeling i

iv

I

$.7 Inadvertent Londina and Doeration of A Tuel Assembiv In An Imnrocer Position 6.0 INCREASE IN REACTOR COOLANT I!NENTORY 6.1 Inadvertent oneration of rces Durina power oneration 6.1.1 Core Cooling Capability Analysis E

6.1.1.1 Nodalization g

6.1.1.2 Initial Conditions 6.1.1.3 Boundary Conditions 6.1.1.4 Control, Protection, and Safeguards System Modeling 6.2.1 Pressurizer Overfill Analysis 6.2.1.1 Initial Conditions 6.2.1.2 Boundary Conditions 6.2.1.3 rN t C '

Protection, and Safeguards System Modeling 7.0 DD,? '4a

".N REACTOR COOLANT I!NENTORY 7.1 intavu tent onenina of a pressurizer safetv or Relief Valve 7.1.1 Nodalization 7.1.2 Initial Conditions 7.1.3 Boundary Conditions 7.1.4 Control, Protection, and Saf eguards Systems ;1odeling 7.2 Steam Generator Tube Runture 7.2.1 Core Cooling capability Analysis

=

7.2.1.1 Nodalization 7.2.1.2 Initial Conditions 7.2.1.3 Boundary Conditions 7.2.1.4 Control, Protection, and Safeguards System Modeling 7.2.2 Offsite Dose calculation Input Analysis 7.2.2.1 Nodalization 7.2.2.2 Initial Conditions 7.2.2.3 Boundary Conditions 7.2.2.4 Control, Protection, and Safeguards System Modeling B.0

SUMMARY

9.0 REFERENCES

I I

I I'

I V

i

l

1.0 INTRODUCTION

This report documents the conservative modeling assumptions used by Duke Power Company in performing the NSSS primary and secondary system l_

analyses of FSAR-Chapter 15 accidents._ lt covers all applicable non-BOCA accidents in Sections 15.1 through 15.6 of the FSAR except those already addressed in Duke Power Company topical report DPC-NE-3001 (Reference 1), which are-steam system piping failure (FSAR Section 15.1.5), control rod misoperation (dropped rod, rod group, or rod bank, FSAR Sections 15.4.3a&b), and rod ejection (FSAR Section 15.4.8).

The or.ly accidents categorized as not applicable are those which 1) do not apply-to McGuire and Catawba (FSAR Sections 15.2.1, 15.5.3, 15.5.4, and 15.6.6), 2) involve no system thermal-hydraulic analysis (FSAR Section 15.6.2), or 3) the current McGuire and Catawba licensing bases regard as being bounded by another accident (FSAR S6ctions 15.2.2, 15.2.4, 15.2.5, 15.3.4, and 15.5.2).

The assumptions discussed in this report are specific choices about the use of the models described in general in DPC-NE-3000 (Reference 2).

The areas discussed are nodalization, initial conditions, boundary conditions, modeling of the process instrumentation and control systens, the Reactor Protection System, the Engineered Safety Features Actuation System, and availability of other important systems and components.

The discussion of the nodalization employed in analyzing a particular accident _ focuses on two main areas.

First, the symmetry.of the accident is examined to determine whether it affects all-Reactor Coolant System (RCS) loops in approximately the same manner, justifying the use of a single RCS loop model, or whether one or more loops must-be modeled separately to conservatively model differential effects of the accident on them.

Second, tha level of detail of the models described in Reference 2 is examined to determine whether they are appropriate for each analysis.

In most-cases the modeling described in Reference 2 is appropriate.

Any inadequate modeling would be upgraded on an accident specific basis to ensure-conservative modeling of the physical phenomena requiring a more detailed model. Modeling regarded as excessively detailed, considering the importance of that area of the system in the particular-accident, might be simplified to reduce the computational costs or the effort required to simulate that section of the model.

The analyses covered by this report are intended to be valid, unless stated otherwise, for both the McGuire and Catawba Nuclear Stationo.

For each analysis, the differences botween the two stations and between the two units at a given station, as discussed in Section 3.1.6 et Reference 2, are considered. A bounding " unit' is selected considering how these differences affect the margin to each acceptance criterion of the accident being analyzed.

In some cases this is an= actual unit,

e.g., the use of Catawba Unit 2 because its steam generator inventory as a-function of power is different from the other three units.

In others it is a superposition of limiting characteristics from more than one

unit, e.g., using steam line safety vsive banks which correspond to the two lowest setpoint-McGuire valves and the three highest setpoint Catawba valves since this artificial bank has a smaller relief capacity

-than-the actual-banks-at-either-station.

In-the future such combined

= -

1-1 i

1

I analyses might be redone separately on a more plant specific basis to gain margin.

The values for relevant plant parameters at the start of each accident are determined through the following process.

First, the value for a given parameter is determined considering normal and off-norN,a1 plant operation. Technical Specification limits, and mode of parameter control (whether controlled by an automatic system or manually by the operator).

Since many of the important parameters are functions of reactor power, some of the parameter value choices are made to be consistent with the l

initial power level for the accident.

Once the parameter value is 5

determined, a method is used to account for uncertainties in this value due to controller tolerance (either manual or automatic) or instrument g

uncertainty. This method might be an explicit adjustrnent to the initial g

value itself or an accounting for the uncertainty in other affected parameters, such as DNBR limits or reactor trip setpoints.

Parameters for which an uncertainty adjustment is made are listed in Table 8-1.

The boundary conditions which affeet the course of the transient are modeled to ensure a conservative result.

Boundary conditions include:

1)

Flows to and from plant components not explicitly modeled, e.g.,

Emergency Cote Cooling System (ECCS) flow rate as a function of ECCS configuration, RCC back pressure, ECCS suction source temperature, pressure, and boron concentration, pump motor starting time, and any postulated pump degradation 2)

Releases through pipe breaks and open valves, including the effects of critical flow 3)

Timing of manual actions 4)

Timing of automatic actions, including the effects of setpoints, setpoint tolerances, and the uncertainties in monitored parameter signals The modeling of boundary conditions is very accident specific and is discussed in detail under each accident.

The plant control systems modeled for accident analyses are described in g

Sections 3.1.4 and 3.2.4 of Reference 2.

Only those control systems g

which have an important effect on the coursa of the accident are considered.

If the operation of a given control system would make the l

accident rnore severe, that system is assumed to function normally.

If its operation would make the accident less severe, the system is not

=

assumed to function. The Reactor Protection System (RPS) and the Engineered Safety FSaturen (ESF) are described in Sections 3.1.5 and E

3.2.4 of Reference 2.

Only those safety systems which have an important g

effect on the course of the accident are considered. The most limiting single active failure of a component to perform its safety functions is considered in accordance with Appendix A to 10 CFR 50.

In general, no credit is taken for components which are not safety grade, although a penalty for their operation might be taken as 1-2

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

described above. Similarly, the availability of non-safety systems and e

components, e.g.,

reactor coolant pumps (RCPs), pressurizer heaters, non-emergency AC power, and instrument air, is only assumed if such availability would make the accident worse.

The list of assumptions for the accidents is summarized in Table 8-1.

Each accident description gives the relevant subset of these assumptions applicable for a particular accident and discusses their bases.

0

' I f

t 1

s p

t k

a b

1-3

2.0 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 2.1 Feedwater svatem Malfunctions That Result in A Peduction in Feedwater Temneraturg A Feodwater System malfunction that results in a decrease in feedwater temperature will cause an increase in core power by decreasing reactor coolant temperature.

Physically, as the cooler feedwater reduces the reactor coolant temperature, positive reactivity will be inserted due to the effect of a negative moderator temperature coefficient.

Postulating that the Rod Control System is in automatic control, control rods would be withdrawn as RCS temperature decreased, inserting additional positive reactivity. The net effect on the RCS due to a reduction in feedwater temperature would be similar to the effect of increasing feedwater flow or increasing secondary steam flows the reactor will reach a new equilibrium condition at a power level corresponding to the new steam generator AT.

A Feedwater System malfunction that results in a decrease in feedwater temperature can be initiated from the following types of events:

spurious actuation of a feedwater heater bypass valve, interruption of steam extraction flow to a feedwater heater (s), spurious startup of a single auxiliary feedwater pump, failure of a single feedwater heater drain pump or failure of all feedwater heater drain pumps.

The above events are examined, with the most limiting determined to be a spurious actuation of a feedwater heater bypass valve.

However, under the current Duke Power company method of analysis, this accident is bounded by quantitative analysis of the increase in feedwater flow event or the excessive increase in secondary steam flow event. These events bound the reduction in feedwater temperature event by producing a greater RCS cooldown. The applicable acceptance criterion is that fuel cladding integrity shall be maintained by ensuring that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations.

2.2 Feedwater system Malfunction causino an increase in Egedwater Flow The malfunctions considered are 1) the full opening of a single main feedwater control valve, 2) an increase in the speed of a single main feedwater pump, 3) the spurious startup of a single auxiliary feedwater pump, or 4) a malfunction which affects more than one loop.

The limiting scenario from among those listed above is evaluated to demonstrate that fuel cladding integrity is maintained by ensuring that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations using the Statistical Cere Design Methodology.

2-1 m

I 2.2.1 Nodalization of the events identified in the previous section, the latter, the multi-loop malfunction, is the most limiting, and is therefore the one that is discussed. This transient affects all loops equally and is therefore analyzed with a single-loop HSSS system model (Reference 2, Section 3.2).

2.2.2 Initial Conditions Core Power Level High initial power level maximizes the primary system heat flux. The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

Preneurizer Pressure The nominal pressure corresponding to full power operation is assumed, u

with the pressure initial condition uncertainty accounted for in the Statistical Core Design Methodology.

pigsgriter Levd Since this accident involves a reduction in RCS volume due to coolant contraction, a positive level uncertainty is applied to the nominal programmed level to minimize the initial proosurizer steam bubble volume and therefore maximize the pressure decrease due to contraction.

Reactor Vessel Averace Temnerature The nominal temperature corresponding to full power operation is assumed, with the temperature initial condition uncertainty accout.ted for in the Statistical Core Dssign Methodology.

RCS Flow The Technical Specification minimum measured flow for power operation is l

assumed since low flow is conservative for DNBR evaluation. The flow

=

initial condition uncertainty is accounted for in the Statistical Core Design Methodology.

Core Dynans Flow The nominal calculated flow is assumed, with the flow uncertainty accounted for in the Statistical Core Design Methodology.

Steam Generator Level A negative level uncertainty is assumed to maximize the margin to a high-high stenm generator narrow range level reactor trip due to any temporary steam /feedwater flow mismatch. This maximizes the duration of the overcooling before it is ended by feedwater isolation.

Fuel Temnerature A low initial temperature is assumed to maximize the gap conductivity calculated for steady-state conditions and used for the subsequent transient. A high gap conductivity minimizes the fuel heatup and attendant negative reactivity insertion caused by the power increase.

I 2-2

This makes the power increase more severe and is therefore conservative l

for DNBR evaluation.

Eteam Generator SMbe Pluccina In order to msximize the effects of the increased secondary system heat removal, no tube plugging is assumed.

t

}

2.2.3 Boundary Conditions Main reedwater Plow

{

A conservatively large step change in nmin feedwater flow to all steam generators is assumed at the initiation of the transient.

A step decrease in main feedwater temperature is assumed to account for the increased main feedwater flow rate.

2.2.4 Control, Protection, and Safeguards Systems Modcling Reactor Trin The pertinent reactor trip functions are the low-low steam generator level, high flux and overpower AT.

The safety analysis setpoint or the initial condition for the monitored parameter contains an allowance for measurement instrumentation uncertainty and setpoint setting tolerance.

Pressurifer Level control No credit is taken for pressurizer level control system operation to compensate for the depressuriration which accompanies RCS volume shrinkage.

Rod control This accident will result in a decrease in RCS temperature. The reduced temperature will cause a positive reactivity insertion through the negative moderator temperature coet'ficient.

With the Rod Control System in automatic control, the control rods may insert due to the mismatch between NI power and turbine power and cause a itegative reactivity insertion. However, since the reactor vessel average temperature is maintained at a programmed value, the control rods may withdraw in an attempt to maintain this temperature and cause a positive rosctivity insertion.

Both automatic and manual control of the Rod control System are analyzed in order to ensure that the worst case is determined.

Turbino control The turbine is modeled in the load control mode, which is describwu an Section 3.2.5.1 of Reference 2.

In this mode any decrease in steam pressure, due for example to a shift from latent to sensible beat transfer because of the overfeed, would be compensated for by an opening of the turbine control valves to maintain impulse chamber pressure at the programmed value.

Auxiliary Feedwater AFW flow would be credited, after the appropriate Technical Specification response time delay, when the safety an-lysis value of the 2-3

I low-low steam generator level setpoint is reached.

However, the parameter of interest for this transient has reached its limiting value before the appropriate Technical Specification response time delay has g

elapsed.

Therefore, no AFW is actually deliverud to the steam g

generators.

Turbine Trio Turbine trip is credited, after the appropriate Technical Specification

=

response time delay, on high-high steam generator narrow range level or on reactor trip.

Feedwater Isolatign Feedwater isolation is credited, after the appropriate Technical g

Specification response tims delay, on high-high steam generator narrow g

range level.

2.3 Excessive Increase in Secondsrv Steam F12W The accident analyzed is a'atep increase in secondary steam flow of r-magnitude equal to that for which the Reactor control System in designeC, 10% of licensed core thernal power.

Incra:ses of larger negnitude are discussed in Section 2.4 and in Chapter 5 of Reference 1 The accident is analyzed to demonstrate that fuel cladding integrity is maintained by ensuring that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations. The minimum DNBR is determined using the Statistical Core Desi n Methodology.

C 2.3.1 Nodalization The accident analyzed is an excessive increase in secondary steam flow at power.

Flow increases from a zero power initial condition are l

evaluated in Section 2.4 and in Chapt 6r 5 of Reference 1.

Per Reference 3,

Section 15.1.4, the power icvel analyzed for this accident should be W

102% of licensed core thermal power for the number of loops initially assumed to be opern.ing. At power, the Technical Specifications require g

all four loops to be operating. Therefore full power 3s assumed as the 3

initial condition.

An increase in steam flow to the turbine would affect all loops equally, therefore, a single-loop NSSS system model (Reference 2, Section 3.2) is used.

2.3.2 Initial Conditions C. ore power Level Per Reference 3, Section 15.1.4, the power level analyzed for this g

accident should be 102% of licensed core thermal power for the number of g

loops initially assumed to be operating.

At power, the Technical Specifications require all four loops to be opertting.

Therefore full 1

power is assumed as the initial condition. The uncertainty in initial power level is accounted for in the Statistical Core Design Methodology.

1 I!

2-4

Preneurirer Premeure The nominal pressure corresponding to full power operation is assumed, with the pressure initial condition uncertainty accounted for in the Statistical Core Design Methodology.

EItanurizer Level Since this accident involves, particularly for the manual Rod Control System operation scenario, a reduction in RCS volume due to coolant contractior., a positive level uncertainty is assumed to minimize the initial pressurizer steam bubble volume and therefore maximize the pressure decrease due to contraction.

Reactor Vennel Averace Temnerature The nominal temperature corresponding to full power operation is assumed, with the temperature initial condition uncertainty accounted for in the Statistical Core Design Methodology.

l RCS Flow The Technical Specification minimum measured flow for power operation is assumed since low flow is conservative for DNBR evaluation. The flow initial condition uncertainty is accounted for in the Statistical Core Design Methodology.

Core Dynamn Flow The nominal calculated flow is assumed, with the flow uncertainty accounted for in the Stat $stical Core Design Methodology.

Steam cenerator Level The results of this transient are not sensitive to the direction of steam generator level uncertainty as long as the transient level response is kept within the range that avoids protection or safeguards actuation.

Egel Temnerature The results of this transient are not sensitive to initial fuel temperature.

Eteam cenerator Tube Pluccina In order to maximise the effects of the increased secondary system heat removal, ao tube plugging is assumed.

2.3.3 Boundary conditions Main Steam Flow A step change in main steam flow to the turbine equal to 10% of full power flow is assumed at the initiation of the transient.

2-5

I 2.3.4 Control, Protection, and Safeguards Systems Modeling Egagtor Trin The reactor is not expected to trip for this transient. However, reactor trip is credited, after the appropriate Technical Spoeification response time delay, if the safety analysis setpoint is exceeded for any reactor trip function.

Figggurirer Level control No credit is taken for pressurizer level control system operation to compensate for the depressurization which recompanies RCS volume shrinkage.

Steam Line PORVs.and condonner Steam Dumn While the steam line PORVs and steam dump might be a source of the increased steam flow in this postulated accident, the case analyzed assumes the increased flow exits to the turbine.

Steam Generator Level control The results of this transient are not sensitive to the mode of steam g

generator level control as long as the level is kept within the range 5

that avoids protection or safeguards actuation.

MFw Pumn sneed control The results of this transient are not sensitive to the mode of MFW pump speed control as long as the steam generator level is kept within the range that avoids protection or safeguards actuation.

Rod control This accident will result in a decrease in RCS temperature. With the Rod Control System in nanual control, the reduced temperature will cause Es positive reactivity insertion through the negative moderator temperature coefficient.

With the Rod control System in automatic control, in which the reactor vessel average temperature is maintained l

at a programped value, the control rods will cause a positive reactivity

=

insertion as they are withdrawn in an attempt to maintain this temperature.

Both cases are analyzed in order to ensure that the worse one is considered.

Turbine control The turbine is modeled as described in Section 3.2.5.1 of Reference 2, with a step increase in flow rate at the beginning of the accident.

Auxillarv Feedwater AFW flow would be credited, after the appropria'.3 Technical B

Spec (fication response time delay, when the safety analysis salue of the low-low steam generator level setpoint is reached.

However, the g

parameter of interest for this transient has reached its limiting value g

before the anoropriate Technical Specification response time delay has elapsed. Therefore, no AFW is actually delivered to the steam generators.

i 2-6

2.4 Inadvertent ODgnina of a Cteam Cencrator Relief or Enfety YAlEn This accident is similar in most respects to the steam line break accident analyzed in Chapter 5 of Reference 1.

If the inadvertently opened valv6 will not rescat, and cannot be isolated by closing a valve in series with it, the effect is the same as a pipe break in the name location and with the same effective flow area.

Because the steam line safety valves and the steam line power-operated relief valves (PORVs) are located upstream of the MSIVs, a r, team line isolation actuation, with or without a failure of a single MSIV, would result in the continued blowdown of the steam generator with the failed valve. The applicable acceptance criterion is that fuel cladding integrity shall be paintained by ensuring that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations. This criterion is satisfied by comparison to the DNDR results for the more limiting steam line break transient. The analytical methodology for the steam line break analysis (Referes.co 1) is applied to an analysis of the inadvertent opening of a steam generator relief or safety valve, with an appropriate adjustment to the break flow area.

2-7

ll l

DukeIvw Company At $ Tuus PO l'M M4 kmw nceiteMet Chwtone, NC 28MI1006 Nuclew Genemw (IN).182!?00 Once (TM)1924360Tu

(

)

DUKE POWER March 15,1996 U.

S. Nuclear Regulatory Commission Washington, D.

C.

20555 Attention:

Document Control Desk 1%

YMS c0 pOj,tjgs4

Subject:

Duke PoWor Company Dggg McGuire Nuclear Station

,ggpA Docket Numbers 50-369 and -370 Catawba Nuclear Station Docket Numbers 50-413 and -414 Safety Valve Modeling Referencoat

1) Nevember 15, 1995 lotter from W.

R. McCollum (DPC) to NRC, " Proposed Technical Specifications (TS) Changes."

2) December 19, 1995 letter from M.

S. Tuckman (DPC) to NRC, " Minor Change to NRC-Approved Methodology."

The purpose of this letter is to provido additional information concerning the two submittals referenced above.

The intent of the November 15, 1995 submittal was to pursue an increase in the main steam code safety relief valvo setpoint tolerance for the current plant configuration.

As such, the transient analyses discussed in the technical justification section were those based on the existing Model D steam generator design.

This submittal is completely independent of steam generator replacement, although the approval of the submittal will affect the replacement steam generator licensing plan as described below.

The corresponding McGuire submittal was approved by the NRC on August 2, 1994.

The December 19, 1995 submittal seeks NRC concurrence for a revision to the pressurizer and main steam safety valve lift modeling in NRC-approved analysis methodologies.

This revision will use a pop-open modeling approach rather than a linear ramping open approach.

This change was made necessary primarily by the turbine trip transient, which was roanalyzed in support of the steam generator replacement.

During the course of this reanalysis, it was discovered that due to the increased heat transfer area of the replacement steam generator, the peak secondary pressure caso did not n~e w are n.

moot tho acceptance critorion.

Below is a summary of the peak secondary prosauro results for the pertinent analysis cases:

Acceptance critorion (110% of 1185 poig) 1303.5 psig Model D S/G E

+3% sotpoint drift, original lift 1295 5

sotpoints, linear ramp model psig Replacement S/G:

+3% sotpoint drift, original lift

>l311 sotpoints, linear ramp model psig

+3% sotpoint drift, reduced lift 1295.8 sotpoints, linoar ramp model poig

+3% setpoint drift, original lift 1285.7 sotpoints, pop-open model psig The revised modeling assumos that the safety valves pop open a

to a full open position in 0.5 seconds after the drifted g

lift sotpoint is reached.

This assumption is based on the attached documents, in which the valve manufacturers, crosby and Dressor, and the McGuiro/ Catawba valvo engineering staff E

concur that this modeling is adequate to conservatively E

bound the performance of both the pressurizer and main steam safety valves.

Approval of the increased sotpoint toleranco g

and NRC concurrence with the revised pop-open modeling g

approach is requested.

No additional Technical Specification changes or engineering effori. are necessary to resolve this issue with this approach.

There are no NUREG-0737 commitments regarding the transient analysis modeling of the safety valves that conflict with this request.

If the increased notpoint tolerance is approved and the valve pop-open modeling is not, the main steam safety valvo setpoints will have to be lowered in conjunction with the a

stoom generator replacement.

This will require submittal of g

additional Technical cpecification revisions.

If the increased tolerance is not approved, the turbine trip analysis will not necessitate any setpoint or valve modeling changes.

However, the consequence of this course of action will be a continuation of licenseo reports and engineering evaluations due to the safety valves failing their Technical Specification surveillance and being declared inoperable.

If you would like to discuss this letter further, please call Scott Gewehr at (704) 382-7581.

Very truly yours,

, S.

M.

S.

Tuckman I

cc Mr. V. Norses, Project Manager office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail stop 14H25, OWFH Washington, D.

C.

20555 Mr. R. E. Martin, Project Manager office of Nuclear Reactor Regulation U..S. Nuclear Regulatory Commission Mail stop 14H25, OWFN Washington, D. C.

20555 Mr. S. D. Ebneter, Regional Administrator U.S. Nuclear Regulatory Commission - Region II 101 Marietta Street, NW - Suite 2900 Atlanta, Georgia 30323 Mr. G. F. Maxwell Senior Resident Inspector McGuire Nuclear Station Mr. R. J. Freudenberger Senior Resident Inspector Catawba Nuclear Station e

I I

ll bxct G.

A. Copp J.

E.

Snyder (Mits)

M.

S. Kitlan (CNS)

G.

D. Swindlehurst l

T.

R. Higgol i

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I; F

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August 29,1995 b.

tr Chsisty Rey AUG a g NODSafety AnalysisOroup OI%E POWER C W M ENowitg $; y L

Re:

McGuire Nuclear Ststion MSSV Opening Response Time Tech Spec Submittal his is to summarire the expected opening response times of the McGuire's Main Steam Safety Valves and to demonstrate that they will open fully within the 0.5 seconds assumed in the Safety Analysis. De following valves were manufactured by Crosby and are the subject of this review.

$1yle Sig Set Pressure Onen Time Tag Nos.

HA 65 FN 6Q8 1870 psig*

0.160 see 1/2 SV2,8,14,20 llA 65 FN 6Q8 1190 psig*

0.090 sec 1/2 SV3,9,15,21 IIA 75 FN 6R10 1205 psig*

0.110 see 1/2 SV4,10,16,22 HA 75 FN 6R10 1220 psig*

0.060sec I/2 SV5,11,17,23 IIA 75 FN 6Rl0 1215 psig unavailable 1/2 SV6,12,18,24 All valves at McGuire were tested at Crosby's high flow test loop to determhied unique ring setting for each valves to assure blowdown performance within a range less than or equal to 10%. De tests simultaneously recorded I) inlet pressure,2) outlet pressure and 3) spindle position on Crosby's Data Acquisition System.

Although the test was not specifically intended to demonstrate the opening response time for the valves, the data did record the opening time for each valve at test conditions with its own unique ring settings.

Crosby recently provided one set of test curves, for one valve at each set pressure indicated above with an asterisk (*). Dese curves (Attachment 1) show typical response time for valvas installed at McGuire.

Crosby has not yet provided curves for all valves but has indicted that these curves should represent the opening response of all MSSV's at McGuire.

Since the Crosby tests were intended primarily to validate ring settings for blowdown performance, the inlet pressure ramp rate was not varied to study its effect on opening times. EPR1, however, conducted extensive tests on Pressuriter Safety Valves as required by NURiiG 0737, %ese test by EPRI on a Crosby style HB.

BP 86, site 6N8, demonstrated no appreciable relationship between inlet pressuritation rate and opening times. With ramp rates varrying between 2 psl/sec and 325 psi /sec, opening times varied little between 0.018 and 0.021 seconds. See Attachment 2, tables 4 2 and 4 3.

Although the Pressuriter Valve tested by BPRI and the Main Steam Saftey Valves tested at Crosby are different styles, they teh have a two-ring internal design and are similar in body site. Tests also demonstrate that both style valves, under varying conditions, open with a rapid " pop" at valve setpoint.

We would expect similar inlet pressurization rates to have little effect on the opening time of the MSSV's.

Derefore, the tests performed by Crosby, coupled with those performed by EPRI demonstrate valve opening response times under various inlet conditions, are well within the assumed time of 0.500 seconds.

If you wish to discuss this subject further, please contact the undersigned at 875 5627.

1A Grant Cutti McGuire Valve Engineering Attachments (2)

~

pet e CrtO B OY N N # #

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$mxb ~.sul<E.OOWER April 12,1995 Rolland S. Huffman, Senior Engineer Dresser Industries PO Box 1430 Alexandria, LA 71309 I;

Subject:

MSSV (Dresser Model 3787) Opening Times gl File No: CN1205.09 5

Dear Sir,

Due to a historica! trend of Main Steam Safety Valve (MSSV) setpoint drift outside of l

+/ 1% and a recon! trend of performance outside of +/- 3 %, Catawba has initiated a comprehensive cakb analysis considering the potentialimpact of MSSV setpoint drift. A f

significant contributor to our computer modeled analysis is the valve " opening" time.

Catawba Engineering believes that Duke Power assumed an overly conservative MSSV Opening Time during the initial safety analysis. Based on review of extensive, well documented EPRI Safety Relief Valve Test Data performed after TMl, as required by NUREG-0737; the opening times of Dresser Pressurizer Safety Valves (PSV) was consistently shown to be less than 0.1 of a second. Multiple tests were performed with Dresser Model 31709na and 31739a PSV's under varied conditions of pressurization rate, system media, ring positions, etc. and validate this position.

in addition, Crosby spring actuated safety valves of similar design, model HB BP 86 GN8, also had opening times of less than 0.1 of a second. The " POP' action of these safety valves is clearly demonstrated by review of these comprehensive EPRI Test Reports.

Attached are excerpts from the EPRI Test neports reptesenting typical test data and graphical plots of both stem position and steam flow vs time. These two parameters distinctly define the valve opening time. A summary of test results are documented on the Test Matrix Table noting g

the valve " simmer" time, " POP' time, pressurization rate, test media, etc. for each test run. In 3

addition, plots for stem movement and steam flow for Dresser test number 603,606,611,and 1305 which are typical and notably represent varied conditions of pressurization ( from 2.9 to g

322 psl/sec ) are attached, g

I k

i l

3...

The following information is a simple summary of key parameters of stem travel, steam flow, and time..which have been recorded from tho attached test data / plots.

Time to FullStem Travel Time to Maximum Steam Flow Pressurization Rate Simmer

• POP Time

(> rated steam flow of 608k Ib/hr)

(psl/sec)

( Rated lift Of.688')

003

.010 see

.000,sec 2.9 000

.020 sec

.070'sec 200 011

.024 se

.072 see 322 1305

.031 sec

.082 sec 308 1202

.020 sec^

not available 2.0 1207

.019 sec not available 317 Catawba does not have actual full flow test data for the Dresser 3787 MSSV's to support the position of valve opening times of.1 of a second, but CNS Engineering believes that the extensive PSV test data adequately demonstrates the " pop' action of a safety valve of this design and that the MSSV opening times will also be less than.1 seconds. Conservatively, Catawba proposes to model the valves with an opening time of.5 of second or over 500% of the slowest time observed for the PSV.

As per our telephone conversation, please raview Catawba's Engineering Evaluation of

(

MSSV opening times and the attached supporting documentation. As the original OEM of Catawba's MSSV's, we need your concurrence of our evaluation that the valves will open in less than.5 seconds, if you concur with the our evaluation please sign below and retum

otherwise, provide comments as to your position and the impected opening time we should assume for our analysis.

t 1

Keil Bibio D eP W r/M uipme t Engineer OEM (Dresser) Engineering Concurrence R.S. Huffman Dresser Industries /SR Engineer k

2 L

um et n us ern uuteu< Lari r.e The following information is a simple summary of key parameters of stem travel, steam flow, and tlrhe which have been recorded from the attached test data / plots.

l Time to Full stem Travel Time to Maximum Steam Flow Pressurization Rate l

Simmer + POP Time

(> rated steam flow of 508k ID/hr)

(pst/sec) g

( Rated lift Of.588 ')

603

.oie see

.080 sec 2.9 COS

.020 sec

.076 sec 296 611

.024 see

.072 sec 322 1305

.031 see

.082 sec 308 1202

.020 see not evallable 2.0 m

1207

.019 sec not available 317

.g A

Catawba does not hava actual full flow test data for the Dresser 3787 MSSV's to support the I

position of valve opening times of.1 of a second, but CNS Engineering believes that the extensive PSV test data adequately demonstrates the " pop" action of a safety valve of this design and that the MSSV opening times will also be less than 1 seconds. Conservatively, Catawba proposes to model the valves with an opening time of.5 of second or over 500% of the slowest time observed for the PSV.

(

As per our telephone conversation, please review Catawba's Engineering Evaluation of g

MSSV opening times and the attached supporting documentation. As the original OEM of g

Catawba's MSSV's, we need your concurrence of our evaluation that the valves will op,en in less than.5 seconds. If you concur with the our evaluation please sign below and return

otherwise, provide comments as to your positlors and the expected opening time we should assume for our analysis.

I h

N ue nt Engineer l

• I' 55 f h.3 SnSek va.\\vt 3 ~lB7 w dl C PS6

^

v/c., a.g v e c.,

',0 5 se.c e e d s.

f.89%dl-

-l OEM (Dresser) Engineeri6(Concurre' ce n

R.S. Huffman 3

Dresser Industries /SR. Enginee.-

E l

2 I

Dukehwar Company M S Tiauw P.O.Bar1006 Senior %ce President Garlane, hr200M006 Nuclear Generation (704)M2200 Omce (704)3824360 Fax DUKEPOWER h

May 16, 1996 U.

S. Nuclear Regulatory Commission WW E D4 Attention: Document Control Desk Washington, DC 20553 0 UKE POWER CO-yg j

(}

Subject:

Catawba Nuclear Station, Unit 1, Docket No. 50-413 McGuire Nuclear Station, Units 1 and 2, s

Docket Nos. 50-369 and 370 M

On May 14, 1996, a conference call was held betwean representatives of Duke Power Company and the NRC Staff.

The purpose of the conference call was to clarify discussions of feedwater system pipe breaks that were provided in a March 15, 1996 Response to an NRC Request for Additional Information.

Consistent with the NRC-approved transient analysis methodology (DPC-NE-3002), the feedwater system pipe break event is analyzed to address two separate acceptance criteria: short-term core cooling (DNB) and long-term core cooling (hot leg boiling).

Previous analyses have shown the feedline break event te be non-limiting with respect to the primary and secondary system pressure limits; therefore, no explicit peck pressure calculations are performed for this event.

The results of the long-term core cooling evaluation, performed in support of the steam generator replacement, show that the pressurizer pressure reaches a peak of slightly less than 2250 psig. This is significantly lower than the corresponding Model D steam generator result.

The primary ceasons for this difference are the increased tube bundle heet transfer area and the elevated feedwater nozzle of the feedring steam generator design.

Both of these tend to enhance the overcooling phase of the feedline break transient and thereby reduce the RCS pressurization.

new w ww-ne

I U.

S. Nuclear Regulatory Commission May 16, 1996 Page 2 Since the intent of the above analy, h Ts tm min'mize the margin to hot leg boiling, assumptiot> were.aade for the a

initial and boundary conditions which minimize the RCS g

pressure.

Were an explicit peak primary system pressure analysis to be performed, many of these assumptions would be reversed.

The impact of the revised assumptions on tha. peak RCS pressure result has not been quantified.

However, due to the large margin to the Standard Review Plan peak primary system pressure acceptance criterion of 3000 psig, this additional analysis was deemed to be unnecessary.

If additional information is required, please call Robert l

Sharpe at (704) 382-0956.

5 I

Very truly yours, b.

D%

M. S. Tuckman Attachments xc:

S.

D. Ebneter Regional Administrator, Region II U. S. Nuclear Regulatory Commission 101 Marietta Street, NW, Suite 2900 Atlanta, GA 30323 R.

J.

Freude'berger Senior Resident Inspector Catawba Nuclear Station G.

F. Maxwell 3

Senior Resident Inapector 3

McGuire Nuclear Station P.

S.

Tam Project Manager, ONRR V.

Nerses Project Manager, ONRR I

I

U S. Nuclear Regulatory Commission May 16, 1996 Page 3 bec: M.

S.

Kitlan J. E.

Snyder G. A. Copp G. B. Swindlehurst T. R. Niggel M.

S. Sills M. R.-Robinson K.

J. Connell NCMPA-1 NCEMC PMPA SREC ELL File CN-1201.37-27 File MC-12Ol.37-27

I 3.0 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 3.1 turbine Trin The turbine trip event causes a loss of heat sink to the primary system.

The mismatch between power generation in the primary system and heat l

removal by the secondary system causes temperature and pressure to

=

increase in the primary and seconda y until reactor trip and/or lift of 5

the pressurizer safety valves and main steam safety valves. The transient is analyzed to ensure that both the peak Reactor Coolant 3

System pressure and the peak Main Steam System pressure remain below the acceptance criterion of 110% of design pressure.

Peak RCS pressure and g

peak Main Steam System pressure are analyzed separately due to the B

differences in assumptions required for a co2servative analysis.

iI 3.1.1 Peak RCS Pressure Analysis 3.1.1.1 Nodalization Since the trarsient response of the turbine trip event is the same for all loops, the single-loop model described in Section 3.2 of Reference 2 is utilized for this analysis.

3.1.1.2 Initial Conditions Core Power Level High initial power level and a positive power uncertainty maximize the primary-to-secondary power mismatch upon turbine trip.

Pressurirer Pressure Positive uncertainty is applied to the initial pressurizer pressure.

High initial pressure reduces the initial margin to the overpressure limit.

Pressurizer Level High initial level minimizes the initial volume of the pressurizer steam space, which maximizes the transient primary pressure response.

Reactor Vessel Averace Temnerature High initial temperaturo maximizes the primary coolant stored energy, h

which maximizes the transient primary pressure response.

5 RCS Flow Low initial flow minimizes the primary-to-secondary heat transfer.

Core Bvnass Flow Core bypass flow is not an important parameter in this analysis.

I 3-1

Steam. Generator Level High initial level minimizes the initial volume of the steam generator steam space, which maximizes the transient secondary pressure response.

Maximum secondary pressurization causes maximum secondary temperature response, which minimizes primary-to-secondary heat transfer.

Fuel Temnerature High fuel temperature, associated with low gap conductivity, minimizes the decrease in the temperature difference across the cladding as moderator temperature increases due to the turbine trip.

This maximizes the transient heat flux and thus maximizes primary-to-secondary heat transfer.

Steam Generator Tube Pluccina A bounding high tube plugging value degrades primary-to-mecondary heat transfer.

3.1.1.3 Boundary Conditions Pressurifer Safetv Valves The pressurizer safety valves are modeled with opening and closing characteristics which maximize the pressurizer pressure.

Steam Line Safetv Valves The steam line safety valves are modeled with opening a.1 closing characteristics which maximize transient secondary side pressure and minimize transient primary-to-secondary heat transfer.

3.1.1.4 Control, Protection, and Safeguards System Modeling Reactor Trin The pertinent reactor trip functions are the overtemperature AT (OTAT),

overpower AT (OPAT) and pressurizer high pressure.

The response time of each of the two AT trip functions is the Technical Specification value. Tne setpoint values of the AT trip functions are continuously computed from system parameters using the modeling described in Section 3.2.4.2 of Reference 2.

In addition, the AT coefficients used in the analysis account for instrument uncertainties.

The response time of the pressurizer high pressure trip function is the Technical Specification value.

Since the pressure uncertainty is accounted for in the initial pressurizer pressure, the pressurizer high pressure reactor wrip setpoint is the Technical Specification value.

Pressurizer Pressure Control Pressurizer pressure control is in manual with sprays and PORVs disabled in order to maximize primary pressure.

3-2

Pressurizer Level Control Pressurizer level control is in manual with the pressurizer heaters locked on in order to elevate primary pressure.

Charging / letdown has negligible impact.

Steam Line PORVs and Condenner Steam Dump Secondary steam relief via the steam line PORVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat transfer.

Steam Generator Level control Feedwater is isolated upon turbine trip. The addition of subcooled feedwater would tend to subcool the w::er in the steam generator, and g

reduce secondary side pressure, g

Rod Control No credit is taken for the operation of the Rod Control System.

Following turbine trip, the turbine impulse chamber pressure is rapidly reduced. The corresponding reduction in the Rod Control System reference temperature would lead to control rod insertion, which would g

lessen the severity of the transient.

E Auxiliarv FeetMiter l

Auxiliary feedwater is disabled. The addition of subcooled auxiliary feedwate-would tend to subcool the water in the steam generator, and reduce secondary side pressure.

I 3.1.2 Peak Main Steam System Pressure Analysis i

3.1.2.1 Nodalization Since the transient response of the turbine trip event is the same for all loeps, the single-loop model described in Section 3.2 of Reference 2

=.

is utilized for this analysis.

I 3.1.2.2 Initial Conditions Core Power Level High initial power level and a positive power uncertainty maximize the primary-to-secondary power mismatch upon turbine trip.

Pressurizer Pre s s ur.g Positive uncertainty is applied to the initial pressurizer pressure. As long as a high pressurizer pressure reactor trip is avoided, maximum g

primary system pressure is conservative in order to delay reactor trip g

on OTAT.

Presturizer Level High initial level minimizes the initial volume of the pressurizer steam space, which maximizes the transient primary pressure response.

I 3-3 g ll l

Reactor Vessel Avernoe Temnerature High initial temperature maximizes the initial Main Steam System pres-sure and the primary coolant stored energy.

RCS Plow High initial flow maximizes the primary-to-secondary heat transfer.

Core Bvnans Plow Core bypass flow is not an important parameter in this analysis Steam Generator Level High initial level minimizes the initial volume of the steam generator steam space, which maximizes the transient seco-dary pressure response.

Puel Temneratt;g High fuel temperature, associated with low gap conductivity, minimizes the decrease in the temperature difference across the cladding as moderator temperature increase 9 'ue to the turbine trip. This maximizes the transient heat flux and ti maximizes primary-to-secondary heat transfer.

Steam Generator Tube r.uocino

",ero tube plugging is modeled to maximize primary-to-secondary heat L

transfer.

3.1.2.3 Boundary Conditions Pressurizer Safetv Valves The pressurizer safety valves are modeled with opening and closing characteristics which maximize the pressurizer pressure.

Steam Line Safetv Valves The steam line safety valves are modeled with opening and closing characteristics which maximize transient secondary side pressure.

3.1.2.4 Control, Protection, and Safeguards System Modeling Reactor Trin The pertinent reactor trip functions are the overtemperature AT (OTAT),

overpower AT (OPAT), and pressurizer high pressure.

- The response time of each of '. s two AT trip functions is the Technical Specification value. The setpoint values of the AT trip functions are continuously computed from system parameters using the modeling described in Section 3.2.4.2 of Refarence 2.

In addition, the AT coefficients used in the analysis account for instrument uncertainties.

The response time of the pressurizer high prescure trip function is the Technical Specification value. The pressurizer high pressure reactor trip setpoint is the Technical Specification value plus an allowance which bounds the instrument uncertainty.

3-4 i

I Pressurizer Pressure control Pressurizer pressure control is in automatic with sprays and PORVs i

enabled in order to prevent a high pressurizer pressure reactor trip actuation prior to OTAT trip actuation.

Eressurizer Level control Pressurizer level control is in manual with the pressurizer heaters locked on in order to elevate primary pressure. Charging / letdown has I

negligible impact.

Steam Line PORVs and Condenser Steam Dumn Secondary steam relief via the steam line PORVs and condenser steam dump is unavailable in order to maximize secondary side pressurizat'.on.

Steam Generator Level control The addition of subcooled feedwater would tend to subcool the water in the steam generator, and reduce secondary side pressure. However, continued feedwater addition will also tend to slow the heatup of the primary system and delay reactor trip on overtemperature AT.

Both cases will be analyzed in order to ensure that the limiting boundary condition is selected.

Rod control No credit is taken for the operation of the Rod Control System.

Following turbine trip, the turbine impulse chamber pressure is rapidly reduced.

The corresponding reduction in the Rod Control System reference temperature would lead to control rod insertion, which would l

lessen the severity of the transient.

E Auxiliary Feedwater Auxiliary feedwater is disabled. The addition of subcooled auxiliary feedwater would tend to subcool the water in the steam generator, and reduce secondary side pressure.

I 3.2 Loss of Non-Emercency AC Power To The Station Auxilieries A loss of non-emergency AC power causes the power supply to all busses not powered by the emergency diesel generators to be lost.

This leads to the trip of both the main feedwater pumps and the rea : tor coolant g

pumps. A primary system heatup ensues, due to both the coastdown of the g

reactor coolant pumps and the loss of main feedwater heat removal. As a result of this heatup, the primary concerns for this event are short-term core cooling capability (LNBR), long-term core cooling capability l

(natural circulation), and primary and secondary system W

overpressurization.

This transient differs from the complete loss of flow transient only in the timing of the insertion of the control rods. Both transients presume reactor coolant pump and feedwater pump trip as the initiating events.

In the lose of flow event, the reactor trips when the reactor coolant pump bus undervoltage setpoint is reached and the rods begin to fall into the core after an instrumentation delay.

In the loss of AC power I

3-5 g

5,

transient, the control-rods begin to fall immediately due to the loss.of gripper coil voltage. : : Therefore, the transient-core power; response and consequently the short-term core cooling capability result (DNBR) is bounded'by the loss of flow event.

Long-term core cooling capability is shown by analyzing the transition from forced flow to natural circulation following a loss of non-emergency AC power.

Similarly, the primary system temperature increase and, therefore, the peak primary system pressure is also bounded by the loss of flow event.

_ Secondary side pressure does not riso-significantly until the turbine trip occurs and: steam-flow is terminated.. The magnitude of this pressure increase is largely determined by the amount of_ heat p

transferred from the primary. system to the secondary once the pressure increase has begun. For this event the recctor trip occurs prior to the turbine trip, such that the primary system heat generation is rapidly decreasing as secon3ary side pressure is increasing. Therefore, the peak secondary pressure result is bounded by the turbine trip event, in-which the reactor trip occurs well after the turbine trip.

[

Based on the above qualitative evaluation, a quantitative analysis of l

this transient is not required except for the long-term core cooling.

ll capability-analysis.

Should a reanalysis become necessary, either.due l

to plant changes, modeling changes, or other changes which invalidate any of the above arguments, the analytical methodology employed would be as follows.

Peak RCS pressure, peak Main 1 Steam System pressure and core cooling capability-(short-term and long-term) are.each analyzed separately-due-to the differences-in assumotions-required for a conservative analysis.

The short-term core cooling capability analysis demonstrates that fuel' cladding.:ntegrity is maintained by ensuring that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations.

~

The minimum DNBR is determined using the Statistical Core Design Methodology. The long-term core cooling capability analysis demonstrates that natural circulation is established.

3.2.1 Peak RCS' Pressure _ Analysis.

= 3. 2.1 '.1

-Nodalization Since the transient response of the loss of offsite power event is the same for'all-loops, the single-loop model described in Section 3.2-of Reference 2 is utilized for this analysis.

3.2.1.2 Initial conditions Core Power Level High initial power level and a positive power uncertainty maximize the primary-to-secondary power mismatch.

-l 3-6

I Pressurifer Pressure Positive instrument uncertainty is applied to the initial pressurizer pressure. High initial pressure reduces the initial margin to the overpressure limit Pressurizer Level High initial level minimizes the initial volume of the pressurizer steam space, which maximizes the transient primary pressure response.

Reactor Vessel Averace Temnerature High initial temperature maximizes the initial primary coolant stored g

energy, which maximizes the transient primary pressure response.

RCS Flow Low initial flow degrades the primary-to-secondary heat transfer.

Core Bvnass Flow l

Core bypass flow is not an important parameter in this analysis.

5 Steam Generator Level Initial steam generator level is not an importatt parameter in this analysis.

Fuel Temnerature l

Low fuel temperature, associated with high gap conductivity, maximizes l

the transient heat transfer from the fuel to the coolant, I

l eam Canerator Tube Pluccino 3

. bounding high tube plugging value degrades primary-to-secondary heat I

transfer, l

l l

3.2.1.3 Boundary Conditions RCP Oceration All four reactor coolant pumps are tripped at the initiation of the transient. The pump model is edjusted such that the resulting coastdown flow is conservative with respect to the flow coastdown test data.

Pressuri er Safetv Valves The presnurizer safety va.ves are modeled with opening and closing characte::istics which maximize the pressurizer pressure.

Steam Line Safetv Valves l

The stean line safety valves are modeled with opening and closing 5

characteristics which maximize transient secondary side pressure and minimize transient primary-to-secondary heat transfer.

3.2.1.4 Control, Protection, and Safeguards System Modeling Beactor Trio The insertion of all control and shutdown banks occurs when the power is lost to the control rod drive mechanism.

3-7 I

Pressurizer Pressure control Prrasurizer pressure control is in manual with sprays and PORVs disabled in order te maximize primary pressure.

Pressurirer Level control Pressurizer level control is in automatic in order to maximize primary pressure. Charging /lerdown has negligible impact.

Steam Line PORVs and Condenser Steam Dumn Secondary stecm relief via the steam line PORVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat transfer.

Auxiliary Feedwater Auxiliary feedwater actuation occurs on the loss of offsite power after an appropriate Technical Specification response time delay.

If applicable, a purge volume of hot main feedwater is assumed to be del 3vered prior to the cold AFW water reaching the steam generators.

Ir l

order to mit.imize the post-trip steam generator heat removal, the l

minimuta auxiliary feedwater flow is assumed.

Turbine Trin l

Turbine trip occurs on the loss of offsite power.

3.2.2 Peak Main Steam System Pressure Analysis 3.2.2.1 Nodalization Since the transient response of the loss of offsite power event is the same for all loops, the single-loop model d3 scribed in Section 3.2 of Reference 2 is utilized for this analysis.

3.2.2.2 Initial Conditions Core Power Level High initial power level and a positive power uncertainty maximize the primary-to-secondary haat transfer.

Pressurizer Pressure Pressurizer pressure is not an important parameter in this analysis.

Pressurizer Level Since initial level primarily affects the transient primary pressure response, it is not an important parameter in this analysis.

Reactor vessel Averace Temnerature High initial temperature maximizes the initial Main Steam Systam pressure and the primary coolant stored energy.

RCS Flow High initial flow maximizes the primary-to-secondary heat transfer.

3-8

I Core Bvnass Flow Core bypass flow is not an important parameter in this analysis.

Steam Generator Level High initial level minimizes tue initial volume of the steam generatur steam space, which maximizes the transient secondary pressure response.

Fuel Temnerature Low fuel temperature, associated with high gap conductivity, maximizes the transient heat transfer f rom the fuel to the coolate.

Steam Generator Tube Pluccina In order to maximize primary-to-secondary heat transfer, no tube plugging is modeled.

3.2.2.3 Boundary Conditions RCP Oneration All four reactor coolant pumps trip on undervoltage, at the initiation of g

the loss of offsite power. The pump model is ad.i.asted such that the g

resulting coastdown flow is conservative with rrepect to the flow coastdown test data.

Pressurizer Safetv Valves The pressurizer safety valves are modeled with opening and closing characteristics which maximize pressurizer pressure.

Steam Line Safetv Valves The steam line safety valves are modeled with opening and closing characteristics which maximize transient secondary side pressure.

3.2.1 4 Control, Protection, and Safeguards System Modeling Reactor Trin The insertion of all control and shutdown banks occurs when the power is lost to the control rod drive mechanism.

[

hessurizer Pressure control The operation of the pressurizer pressure control system is not important in this analysis.

Pressurizer Level Control The operation of the pressurizer level control system is not i.aportant w

in this analysis.

Steam Line PORVs and Condenser Steam Den Secondary steam relief via the steam line PORVs and condenser steam dump is unavailable in order to maximize secondary side pressurizatiot.

I I

3-9 j

i

Aurillarv Feedwater

-Auxiliary _feedwater actuation occurs on the loss of offsite power after-E the appropriate Technical Specification response time delay.

If-applicable,'a purge volume of hot main feedwater is assumed to be delivered prior to the cold AFW water-reaching the steam generators. - In order to minimize the post-trip; steam generator heat remova), the minimum auxiliary feedwater flow is assumed.

Turbine Trin

-. Turbine trip occurs on the loss of offsite-power.

3.2.3 Core Cooling capability Analysis - Short Term 3. '2. 3.1 Nodalization lSince the' transient response.of the loss of offsite power event,is the l_

same for all' loops, the single-loop model described in Section 3.2 of

'~

Reference 2 is utilized for this analysis.

3.2.3.2 Initial Conditions Core Power Level.

.High initial. power level maximizes the primary-system heat flux. The-

-uncertainty in this parameter-is accounted for in the Statistical Core Design Methodology, t

Preneurimer Preneure:

Nominal full power pressuri er pressure is assumed. The uncertainty in t

this parameter is accounted'for in the, Statistical Core Design-Methodology.

' Pressurizer Level Low initial level increases the volume of the pressurizer steam space which minimizes the pressure' increase resulting from the.insurge.

Reactor Vemmel Averace Tamneraturc Nominal. full power vessel average temperature is' assumed..The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

RCS Flow Technical Specification minimum neasured Reactor Coolant System flow -is ass

'ed.

The uncertainty in this. parameter is accounted.for in the Stat.stical Core Design Methodology.

Core Evnaam Flow The nominal calculated flow is assumed, with the flow uncertainty

' accounted for in the Statistical Core Design Methodology.

3-10

I Steam Generator Level Initial steam generator level is not an important parameter in this analys's.

Fuel Tennerature A high initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequent h

transient. A low gap conductivity minimizes the transient change in a

fuel rod surface heat flux associated with a power decrease. This makes the power decrease less severe and is therefore conservative for DNBR evaluation.

Steam Generator Tube Pluccina Steam generator tube plugging is not an important parameter in this analysis.

3.2.3.3 Boundary Conditions Reactor coolant Pumns All reactor coolant pumps are assumed to trip on undervoltage at the initiation of the loss of offsite power. The pump model is adjusted such that the resulting coastdown flow is conservative with respect to the flow coastdown test data.

Decav Heat End-of-cycle decay heat, based upon the ANSI /ANS-5.1-1979 standard plus l

a two-sigma uncertainty, is employed.

5 Steam Line Safetv Valves The main steam code safety valves are modeled with opening and closing characteristics which maximize secondary side pressure and minimize primary-to-secondary heat transfer.

I 3.2.3.4 Control, Protection, and Safeguards System 14odeling Reactor Trin The insertion of all control and shutdown banks occurs when the power is lost to the control rod drive mechanism.

I Pressurizer Pressure Control Pressurizer sprays and PORVs are assumed to be operable in order to minimize the system pressure throughout the transient.

Pressurizer Level Control Pressurizer heaters are assumed to be inoperable so that Reactor Coolant System pre =sure is minimized.

Charging / letdown has negligible impact.

Steam Line PORVs and Condenser Steam Dumn Secondary steam relief via the steam line PORVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat transfer.

I 3-11

Auxiliary Feedwater Auxiliary feedwater actuation occurs on the loss of offsite power after the appropriate Technical Specification response time delay.

If applicable, a purge volume of hot main feedwater is assumed to be delivered prior to the cola AFW water reaching the steam generators.

In order to minimize the post-trip steam generator heat removal, the minimum auxiliary feedwater flow is assumed.

Turbine Trin Turbine. trip occurs on the loss of offsite power.

i.2.4 Core cooling capabilit/ Analysis - Long Term 3.2.4.1 Nodalization Since the transient response of the loss of offsite power event is the l

same for all loops, the single loop model described in Section 3.2 of.

Reference 2 is utilized for this analysis.

3.2.4.2 Ini*,ial Conditions Core Power Level High initial power level and a positive power uncertainty maximize the primary system heat source.

Pressurizer Pressure The nominal pressure correspo. ding to full power operation is assumed

-since the establishment of nocural circulation is independent of initial pressurizer pressure.

Pressurl?er Level The nominal level corresponding to full power operatio, is assumed since the establishment of natural circulation is independent of initial pressurizer level.

Reactor Vessel Averace Tamnerature High initial temperature maximizes the amount of stored energy in the primary system that must be removed by the secondary system.

RCS Flow Technical Specification minimum measured Reactor Coolant System flow is assumed since initial RCS flow has little impact on the final natural circulation flow.

Core Bvnans Flow Core bypass flow is not an important parameter in tuis analysis.

Steam Generator Level high initial steam generator level minimizes the initial volume of the steam generator steam space, which maximizes the transient secondary pressure respo se.

Maximum secondary pressurization causes maximum 3-12 I

1 s

I J

secondary temperature response, which minimizes primary-to-secondary heat transfer.

Fuel Temnerature Initial fuel temperature is not an important parameter in this analysis.

Steam Generator hibe Plucci 2 A bounding high tube plugt,ing value degrades primary-to-secondary heat

=

transfer.

I 3.2.4.3 Boundary Conditions Reactor Coolant Pumns All reactor coolant pumps are assumed to trip on undervoltage at the initiation of the loss of offsite power.

Decav Heat End-of-cycle decay heat, based upon the ANSI /ANS-5.1-1979 standard plus a two-sigma uncertainty, is employed.

Steam Line Sr.fetv Valves The main steam code safety valves are modeled with opening and closing characteristics which maximize secondary side pressure and minimize I

primary-to-secondary heat transfer.

3.2.4.4 Control, Protection, and Safeguards System Modeling Reactor Trin The insertion of all centrol and shutdown banks occurs when the power is lost to the control rod drive mechanism.

Pressurizer Pressure control Pressurizer sprays are lost when the reactor coolant pumps trip, a

Pressurizer PORVs are lost when offsite power is lost.

Therefore, both are inoperable.

Pressurizer Level Control Pressurize: heaters are assumed to be inoperable since they are lost when offsite power is lost.

Charging /letoown has negligible impact.

Steam Line PORVs and Condenser Steam Dumn Secondary steam relief via the sta.m line PORVs and the condenser steam l

dump is unavailable due to the loss of offsite power.

W Auxiliarv Feedwater Auxiliary feedwater actuation occurs on the loss of offsite power after the appropriate Technical Specification response time delay.

In order to minimize post-trip steam generator heat removal, the minimum auxiliary feedwater flow is assumed.

Turbine Trin Turbine trip occurs on the loss of offsite power.

3-13

'3,3 Loan Of Normal Feedwater A loss of normal feedwater flow event could result due to the failure of both of the main feedwater pumps or a. malfunction of the feedwater control valves. A primary system heatup ensues due to the degradation of the secondary heat sink. As a result of this heatup, the primary

concerns for this event are-core cooling capability and primary and.

secondary system overpressurization.

The-loss of normal feedwate; transient is bounded by the turbine trip transient.

Both transients involve a mismatch between primary heat-source and secondary heat sink, but the mismatch is greater for-the turbine trip.- This-is mainly due to the reactor trip and turbine trip

occurring simultaneously for the loss of feedwater event, whereas reactor trip lags the turbine trip during the turbine trip cransient, i-Based on the above qualitative evaluation, a quantitative analysis of this transient is not required. Should a reanalysis become necessary, either.due to plant changes, modeling cha.,ges, or other changes which-invalidate any of the above erguments, the analytical methodology employed would be as follows.

Peak RCS pressure, peak Main Steam System pressure and core cooling capability are each analyzed separately due to the differences in assumptions required for a conservative analysis.- The core cooling-capability analysis demonstrates that the Auxiliary Feedwater System is capable of returning the plant to a stabilized condition and that fuel

cladding integrity is maintained by ensuring that the minimum DNBR 1 remains above the 95/95 DNBR limit based on acceptable correlations.

-The minimum DNBR is determined using the Statistical Core Design Methodology.

3.3.1 Peak rcd: Pressure Analysis-3.3.1.1 Nodalization Since the' transient response of the loss of normal feedwater event is the same for all loops, the single-loop model described in Section 3.2 of Reference 2 is utilized for this analysis.

3.3.1.2 Initial Conditions 1

Core Power Level

-High' initial power level and a positive power uncertainty maximize the primary-to-secondary power mismatch.

-Prenmurizer Pressure Positive instrument uncertainty is applied to the initial pressurizer

-pressure.

High initial pressure reduces the initial margin to the overpressure limit.

3-14

_a

I i

Pressurizer Level High initial level minimizes the initial volume of the pressurizer steam space, which maximizes the transient primary pressure response.

Reactor Vessel Avernae Temnerature High initial temperature maximizes the initial primary coolant stored energy, which maximi:es the transient primary pressure response.

RCS Flow Low initial flow degrades the primary-to-secondary heat transfer.

Core Evnass Flow Core bypass flow is not an important parameter in this analysis.

Steam Generator Level Low initial level is assumed in order to minimize steam generator inventory at the tine of reactor trip.

The low-low level trip setpoint l

is adjusted to account for the difference between actual level and 5

indicated level.

Fuel Temnerature Low fuel temperature, associated with high gap conductivity, maximizes the transient heat transfer from the fuel to t5a coolant.

Steam Generator Tube Pluccina A bounding high tube plugging value degrades primary-to-secondary heat transfer.

3.3.1.3 Boundary Conditions PressuriTer Safetv Valves The pressurizer safety valves are modeled with opening and closing characteristics which maximize the pressurizer pressure.

Steam Line Safetv Valves The steam line safety valves are modeled with opening and closing g

characteristics which maximize transient secondary side pressure and g

minimize transient primary-to-secondary heat transfer.

Decav Heat End-of-cycle decay heat, based upon the ANSI /ANS-5.1-1979 standard plus a two-sigma uncertainty, is employed.

I 3.3.1.4 Control, Protection, and Safeguards System Modeling Reactor Trio Reactor trip occurs on overtemperature AT, pressurizer high pressure, or when the low-low level setpoint is reached in the steam generator.

I I

3-15

Pressurizer Pressure control Pressurizer pressure control is in manual with sprays and PORVs disabled in order to maximize primary pressure.

Pressurizer Level control Pressurizer level control is in automatic in order to maximize primary pressure.. Charging / letdown has negligible impact.

Eteam Line PORVs and condenner Steam Dumn Secondary steam r$ lief via the steam line PORVs and the condenser steam dung is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat transfer.

Rod control No credit is taken for the operation of the Rod Control System for i.his transient, which results in an increase in RCS temperature. With the Rod Control System in automatic, the control rods would cause a negative reactivity addition as they are inserted in an attempt to maintain RCS temperature at its nominal value.

1 Turbine control The turbine is modeled in the load :ontrol mode, which is described in Section 3.2.5.1 of Reference 2.

Auxiliarv Feedwater Auxiliary feedwater actuation occurs on low-low steam generator level

(

after the appropriate Technical Specification response time delay.

If

)

applicable, a purge volume of hot main feedwater is assumed to be l

delivered prior to the cold AFW water reaching the steam generators.

In order to minimize the post-trip steam generator heat removal, the minimum auxiliary feedwater flow is assumed.

l l'

3.3.2

-Peak Main Steam System Pressuru Analysis 3.3.2.1-Nodalization Since the transient response of the loss of normal feedwater event is the same for all loops, the single-loop model described in Section 3.2 of Reference 2 is utilized for this analysis.

3.3.2.2 Initial Conditions core Power Level

/

High initial power level and a positive power uncertainty maximize the primary-to-secondary power mismatch.

EIRS.Eurizer Pressure Pressurizer pressure is not an importa.S rameter in this analysis.

Pressurizer Level Pressurizer level is not an important parameter in this analysis.

3-16

I Reactor Vessel Averace Temnerature High initial temperature maximizes the initial Main Steam System pres-sure and the primary coolant stored energy.

RCS Flow High initial flow maximizes the primary-to-secondary heat transfer.

Core Dvoans Flow Core bypass flow is not an important parameter in this analysis.

Steam Generator Level Low initial level is assumed in order to minimize steam generator inventory at the time of reactor trip. The low-low level trip setpoint is adjusted to account for.he difference between actual level and indicated level.

Fuel Temneraturg Low fuel temperature, associated with high 5,ap conductivity, maximizes e

the transient heat transfer from the fuel to the coolant.

Steam Generator Tube Pluccino Zero tube plugging is modeled to maximize primary-to-secondary heat transfer.

3.3.2.3 Boundary Conditions Pressurizer Safetv Valves The pressurizer safety valves are modeled with opening and closing characteristics which maximize the pressurizer pressure.

Steam Line Saferv Valves l

The steam line safety valves are modeled with opening and closing characteristics which maximize transient secondary side pressure.

Decav Heat End-of-cycle decay heat, based upon the ANSI /ANS-5.1-1979 standard plus g',

a two-sigma uncertainty, is employed.

g 3.3.2.4 Control, Protection, and Safeguards System Modeling Reactor Trin l

Reactor trip occurs on overtemperature AT, pressurizer high pressure, gl or when the low-low level setpoint is reached in the steam generator.

W l Pressu? _rer Pressure Control The results of this transient are not sensitive to the operation of pressurizer pressure control as long as the pressure is controlled to within the range that avoids protection or safeguards actuation.

E I

3-17 I

Pressurizar Level-control The results of this transient are not sensitive to the operation of pressurizer level control as long as the level is kept within the range

-that avoids protection or safeguards actuation.

Stamm Line PORVs and condanner Steam Dumn Secondary' steam relief via the steam line PORVs and condenser steam dump

.is unavailable in order to maximize the transient secondary side pressurization.-

Rod control No credit-is taken for-the operation of the' Rod Control System for this

' transient, which results in an increase in RCS temperature.' With the:

Rod Control System in automatic, the control rods would cause a negativt

reactivity l addition as.they are inserted in an attempt to maintain RCS temperature at-its nominal value.

Turbine control The. turbine is modeled in-the load control mode, which is described in Section 3.2.5.1 of Reference.2.

[-

Aurillarv Feedwater Auxiliary feedwater actuation occurs on low-low steam generator level iafter-the appropriate Technical Specification response time deluy.- If applicable,;a purge volume of hot main feedwater is assumed'to be-p delivered prior to the cold AFW water reaching the steam. generators.

i ltn order to minimize the post-trip-steam generator' heat removal, the minimum auxiliary feedwater -flow is assumed.

-3.3.3

- Core Cooling Capability Analysis :

i3'.'3.3.1 Nodalization Since the transienc response of the loss of normal feedwater-event is

-the'same for all-loops, the single-loop model described in Section 3.2 Lof Reference 2 is utilized for this analysis.

Initial Conditions-

=3.3.?

Core Power Level High. initial power level maximizer the primary system heat flux. The

uncertainty in this parameter is accounted for in the Statistical Core Denign Methodology.

Preneurizer Pressure

-Nominal full power pressurizer pressure is assumed. The uncertainty in this patameter is accounted for in the Statistical Core Design Methodology.

3-18

I Pressurizer Level Los initial level increases the volume of the pressurizer steam space which minimizes the pressure increase resulting from the insurge.

Reactor Vessel Averace Tornerature Nominal full power vessel average temperature is assumed. The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

=

RCS Flow Minimum measured Reactor Coolant System flow is assumed. The g

uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

Core Bvnass Flow The nominal calculated flow is assumed, with the flow uncertainty accounted for in the Statistical Core Design Methodology.

Sipam Generator Tube Pluccing A bounding high tube plugging level impairs the ability of the secondary side to remove primary side heat.

Fuel Temneraturg A high initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequent transient.

A low gap conductivity minimizes the transient change in l

fuel rod surface heat flux associated with a power decrease. This makes the power decrease less severe and is therefore conservative for DNBR W

evaluation.

Steam Generator Level Low initial level is assumed in order to minimize steam generator inventory at the time of reactor trip. The low-low level trip setpoint h

is adjusted to account for the difference between actual level and indicated level.

W 3.3.3.3 Boundary conditions Steam Line Safetv Valves The main steam code safety valves are modeled with opening and closing characteristics which maximize secondary side pressure and mininiize primary-to-secondary heat transfer.

Decav Heat End-of-cycle decay heat, based upon the ANS1.\\NS-5.1-1979 standard plus a two-sigma uncertainty, is employed.

I I.

i 3-19

3'.3.3.4I Control, Protection, and Safeguards System Modeling Rameter Trin Reactor trip occurs on overtemperature AT, pressurizer high pressure, or-when the low-low level setpoint is reached in the steam generator.

Prammurirar Prammura control Pressurizer sprays and PORVs are assumed to le operable in order to minimize the system pressure throughout_th sient.

Prammurinar Laval control

'No credit is-taken for pressurizer heater.

_ ion so that Reactor-Coolant System pressure is minimized. Che n letdown has negligible INpact.

Stamm Line PORVs and OnnAmnmar Stamm Dumn Secondary steam relief via-the_ steam line PORVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization

)

l.

and w.nimize transient primary-to-secondary heat transfer.

Rod' control' No credit is taken for the operation of the Rod Control System for this transient, which results in an-increase in RCS-temperature. With the Rod Control System in automatic, the control rods would cause a negative reactivity addition as.they are inserted in an attempt to maintain RCS

~temperatureLat its nominal value.

.Turbina control-

-The turbine is modeled in the load control-mode, which is described in

.Section 3.2.5.1 of-Reference 2.

Auv111arv Feedwater

. Auxiliary feedwater actuation occurs on low-low steam generator level afterethe appropriate Technical Specification response time dslay.

If c

applicable, a purge volume of hot main feedwater is assumed to be'

- delivered prior - to : the cold AFW water reaching the steam generators. In-order.to minimize the post crip steam. generator heat removal, the minimum auxiliary feedwater flow-is assumed;-

Turbina Trin Turbine trip occurs on reactor trip.

L3.4 Feedwater Svatem Pine Break The feedwater system pipe break event postulates a rupture of the Main Feedwater System piping just upstream of the steam generator (downstream-of the final feedline check valve).

Following the blowdown of the faulted' generator, there is a mismatch between the heat generation in

'the reactor and the secondary _ side heat removal-rate. Due to the mismatch, the primary concern for this transient is the capability to effectively cool the reactor core.

3-20

I Adequate short term and long term core cooling capability are analyzed separately due to the differences in assumptions required for a conservative analysis. The short term core cooling capability analysis demonstrates that fuel cladding integrity is maintained by ensuring that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations. The minimum DNBR is determined using the Statistical Core h

Design Methodology. The long term core cooling capability analysis demonstrates that no hot leg boiling occurs.

3.4.1 Short Term Core Cooling Capability The DNB analysis for this transient is modeled as a complete loss of coolant flow event initiated from an off-normal condition. The loss of flow is assumed to occur coincident with the OTAT reactor trip caused by the feedline break hertup.

I 3.4.1.1 Nodalization Since the complete loss of flow transient is symmetrical with respect to the four reactor coolant loops, a single-loop model (Reference 2, Section 3.2) is utilized for this analysis.

3.4.1.2 Initial Csaditions Core Power Level High initial power level maximizes the primary system heat flux. The uncertainty in this parameter is accounted for in the Statistical Core g

Design Methodology.

g Eressurizer Pressure Nominal full power pressurizer pressure is assumed.

The uncertainty in this parameter is accounted for in the Statistical Core Design e

Methodology.

Pressurizer Level Low initial level increases the volume of the pressurizer steam space which minimizes the pressure increase resulting from the insurge.

Reactor Vessel Averace Temnerature Nominal full power vessel average temperature is assumed. The uncertainty in this parameter is accounted for in the Statistical Core l

Design Methodology.

W RCS Flow E

Minimum measured Reactor Coolant System flow is assumed. The E

uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

I 5

core Evnaam Flow The nominal calculated flow is assumed, with the; flow uncertainty accounted;for'in the Statistical Core Design Methodology.

Fuel T==nerature A'high-initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequent transient. A low gap conductivity minimizes the transient change in fuel rod surface heat flux associated with a power decrease. -This makes the power decrease less severe and is therefore conservative for DNBR evaluation.

Stamm Canarator Level Initial steam generator level is not an important parameter in thisE analysis.-

Stamm Generator Tube Pluaalna For transients of such short duration, steam generator tube plugging 1does not have an offect on the transient results.

F '

3.4.1.3 Boundary conditions stamm Line safe *q* Valven The main steam code safety valves are modeled with opening-and closing

-characteristics which maximize secondary side pressure and minimize

. primary-to-secondary heat' transfer.

--3. 4.1. 4 '

control, Protection, andl Safeguards System Modeling Reactor Trin

-Reactor trip occurs on overtemperature AT following-the heatup due-to

-the heat; transfer mismatch.

Earlier trips on high containment. pressure

safety;injeccion and low-low steam generator level are not credited in

order to maximize the primary system heatup.

Pressuriner Pressure control Pressurizer sprays and PORVs are assumed to be operable _in order to minimize the system pressure throughout-the transient.

Pressuriner Level control p

Pressurizer heaters.are assumed to be inoperable so that Reactor Coolant

. System pressure is minimized.- - Charging / letdown has negligible impact.

Stamm Line PORVs and cnndanner Stamm Dumn Secondary steam relief.via the steam line PORVs and the condenser steam damp is unavailable in order = to maxindze secondary side pressurization and minimize transient primary-to-secondary heat transfer.

[ Rod control-No. credit is taken for the operation o; the Rod Control System for this 1 transient, which results in an increase in RCS temperature. With the 3-22

I Rod Control System in automatic, the control rods would cause a negative reactivity addition as they are inserted in an attempt to maintain RCS temperature at its nominal value.

Turbine Control The turbine is modeled in the load control mode, which is described in Section 3.2.5.1 of Reference 2.

Auxiliary Feedwater AFW flow would be credited when the safety analysis value of the low-low l

steam generator level setpoint is reached.

However, the parameter of M

interest for this transient has reached its limiting value before the appropriate Tochnical Specification response time delay has elapsed.

Therefore, no AFW is actually delivered to the steam generators.

Turbine Trin The reactor trip leads to a subsequent turbine trip.

3.4.2 Long Ter-core Cooling capability 3.4.2.1 Nodalization Due to the asymmetry of the auxiliary feedwater flow boundary condition in the feedline break transient, a three-loop model (Reference 2,Section l

3.2), with two single loops and one double loop, is utilized for this analysis.

W 3.4.2.2 Initial Conditions Core Power Le',.gl High initia.' power level and a positive power untertainty maximize the primary system heat load.

Pressurizer Pressure Low initial pressure causes a corresponding decrease in the hot leg W

saturation temperature, which minimizes the margin to hot leg boiling and is conservative for demonstrating long term core cooling.

Pressurizer Level Low initial level increases the volume of the pressurizer steam space which minimizes the pressure increase resulting from the insurge.

Reactor Vessel Averace Temnerature High initial temperature increases the stored energy in the primary system which must be removed by the degraded secondary side.

RCS Flow Low initial flow degrades the primary-to-secondary heat transfer.

Core Bvnass Flow Core bypass flow is not an important parameter in this analysis.

3-23 i

l

Steam Generator Level Low initial level in all steam generators decreases the long-term capability of the secondary system to remove primary system heat.

Fuel Temnerature A conservatively high initial fuel temperature is assumed in order to maximize the amount of stored energy that must be removed.

-Steam Generator tube Pluccina Tube plugging does not significantly affect the transient results so long as the minimum Technical Specification RCS flow rate is used.

3.4.2.3 Boundary Conditions Break Meieling The feedline break is modeled as a double-ended rupture of the main feedwater line just upstream of the steam generater (downstream of the check valve). A bounding flow area of the break junction is assumed in order to maximize the break flow rate.

The break flow rate is l

determined by the Henry (subcooled) and Moody (saturated) critical flow correlations.

Reactor Coolant Pumns The reactor coolant pumps are lost at the. initiation-of the loss of offsite power which occurs coincident with reactor trip.

Offsite Power offsite power is assumed to be lost coincident with reactor trip to delay safety injection and accelerate the post-trip heatup due to the loss of the reactor coolant pumps.

Prersurizer Safetv Valves The pressurizer safety valves are modeled with opening and c1csing characteristics which minimize pressurizer pressure.

Steam Line Safetv Valves The main steam code safety valves are modeled with opening and closinc characteristics which maximize secondary side pressure and minimize primary-to-secondary heat transfer.

Decav Heat End-of-cycle decay heat, based upon the ANSI /ANS-5.1-1979 standard plus a two-sigma uncertainty, is employed.

3.4.2.4 control, Protection, and Safeguards Systera Modeling Reactor Trin The reactor is tripped 10 seconds into the transient. This is assumed to be after the occurrence of safety injection actuation on high containment pressure.

3-24

ll 1

Pressurizer Pressure control Since low Reactor Coolant System pressure is conservative and the blowdown pressure of a cycling safety valve is much lower than for a g

cycling PORV, the PORVs are assumed inoperable.

Pressurizer spray is 3

andumed to be operable in order to minimize system pressure.

Prensurizer level control Pressurizer heaters are assumed to be inoperable so that Reactor Coolant System pressure is minimized. Charging / letdown has negligible impact.

steam Line PORvs and condenser steam Dumn Secondary steam relief via the steam line PORVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat transfer.

Rod control No credit is taken for the operation of the Rod Control System for this transient, since the pre-trip RCS temperature change is insufficient to

=

cause rod motion.

TuIbine control The turbine is modeled in the load control mode, which is describad in Section 3.2.5.1 of Reference 2.

Safetv Indection Safety injection actuation occurs at 10 seconds on high containment pressure.

Injection begins after the appropriate Technical l

Specification delay to allow for the startup of the diesel generrtors on W

the loss of offsite power. One-train minimum injection flow, as a function of RCS pressure, is assumed to minimize the delivery of cold SI water. Injection is stopped when the emergency procedure SI termination criteria are met.

Auxiliarv Feedwater Auxiliary feedwater actuation occurs on safety injection actuation after the appropriate Technical Specification response time delay.

If applicable, a purge volume of hot water is assumed to be delivered prior l

to the cold AFW water reaching the steam generators. Operator action to W

isolate AFW flow to the faulted generator occurs with a conservative delay time to minimize the amount of cold AFW flow to the faulted generator.

In order to minimize the post-trip steam generator heat removal, the minimum auxiliary feedwater flow is assumed.

MSIV closure Early MSIV closure is conservative since it accelerates the heatup portion of the transient due to the faulted SG reaching dryout sooner following MSIV closure. Main steam line isolation occurs on low steam g

line pressure or high-high containment pressure.

Since neither of these g

setpoints can be reached before reactor trip, it is conservatively assumed that MSIV closure occurs coincident with turbine trip.

I 3-25 t

l l

i l

l 4.0 DECREASE IN REACTOR COOLANT SYSTEM FLOW RATE 4.1 Partial tota of Forced Reactor coolant Flow l

A partial loss of forced reactor coolant flow can result from a 1

mechanical or electrical failure in a reae.or coolant pump, or from a j

fault in the power supply to the pump.

If the reactor is at power when such a fault occurs, this could result in DNP with subsequent fuel damage if the reactor is not tripped promptly. The necessary protection l

against a partial loss of coolant flow is provided by the low reactor coclant flow reactor trip signal.

The acceptance criteria for this analye 5 are to ensure that there is adequate core cooling capability and ttt'. the pressure in the Reactor Coolant System remains below 110% of design pressure.

The cora cooling capability analysis demonstrates that fe:1 cladding integrity is main-tained by 2nsuring that the minimun DNBR remains above the 95/95 DNDR limit based on acceptable correlations.

The minimum DNBR is determined using the Statistical Core Design Methodology.

The peak RCS preesure criterion is met through a comparison to the peak pressure results for the more limiting locked rotor transient.

In Section 4.3 of this report, the locked rotor event is shown to remai.n below 110% of the RCS design pressure.

4.1.1 Nodalization This non-symmetric transient is analyzed using a two-loop model, with a single loop for the tripped reactor coolant pump and an intact triple loop.

4.1.1 Initial conditions core Power Level High initial power level maximizes the primary system heat f?.ux.

The uncartainty for this parameter is incorporated in the Statistical Core Design Methodology.

Preneur1rer Preosurg The nominal pressure corresponding to full power operation is assumed, with the uncertainty for this parameter incorporated in the Statistical Core Design Methodology.

Ergagurizer Level Low initial level increases the volume of the pressurizer steam space which minimites the pressure ar:rease resulting from the insurge.

Reactor Vessel Averace Temnerature The nominal temperature corresponding to full power operation is acaumed, with the uncertainty for this parameter incorporated in the Statistical Core Design Methodology.

4-1

I I

RCS Flog The Technical Specification minimum measured flow for power operation is assumed since low flow is conservative for DNBR evaluation.

The g

uncertainty for this parameter is incorporated in the Statistical Core g

Design Methodology, core Dvoans riow The nominal calculated flow is assumed, with the flow uncertainty accounted f or in the Statistical Core Design Methouolorry.

Steam Generator Level Initial steam generatos level is not an irportant parameter in this analysis.

Egel Temperature A high initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequent l

transient. A low gap conductivity minim!.zes the transient change in fuel rod surft*e heat flux associated with a power decrease. This makes the power decrease less severe and is therefore conservative for DNBR evaluation.

Steam Generator Tube Pluacina For transients of such short duration, steam generator tube plugging does not have an eifect on the transient results.

4.1.3 Boundary conditions RCP Oneration A single reartor coolant pump is assumed to trip.

The other three reactor coolant pumps remain operating for the duration of the transient. The reactor coolant pump model is adjusted such that the resulting pump coastdown is conservative with respect to the flow coastdown test data.

g Steam Lipe Safetv Valven The main steam cede safety valves are mode'ed with opening and closing W

characteristics which maximite 3condary pressure and minimize primary-to-secondary heat transfer.

4.1.4 Control, Protection, and Safeguards System Modeling Reactor Trio A reactor trip signal is generated when flow in the affected loop falls below a setpoint which conservatively bounds the Technical Specification R

value.

A delay time consistent with the Technical Specifications is 3

assumed between receipt of the low flow signal and the initiation of control rod motion.

I 4-2

l l

Erggf.uI.1 ter Prensure centrol Prescuriter sprays and PORVs are assumed to be operable in order to minicize the system pressure throughout the transient.

Pressoufrer Level control Pressurizer heaters are assumed to be inoperable so that Reactor Coolant System pressure is minimized. Charging / letdown has negligible impact.

Steam Line PORVm and condanner Steam Dumn Secondary steam relief via the steam line PORVs and the condenser steam

-dump is unaval.loble in order to maximize secondary side pressurization and minimite transient primary-to-secondary heat transfer.

Steam Generator Level control The results of this transient are not sene'tive to the mode of steam generator level control as long as the *.. vel is kept within the range that avoids protection or safeguards actaation.

MFW Pomn Eneed control The results of this transient are not sensitive to the mode of MFW pump speed control as long as the steam generator level is kept within the range that avoids protection or safeguards actuation.

Rod control No credit is taken for the operation of the Rod Control System for this transient, which results in an increase in RCS temperature. With the Rod Control System in autonatic, the control rods would cause a negative reactivity addition as they are inserted in an attempt to maintain RCS temperature at its nominal value.

I Turbine control

~

The turbine is modeled in the load control mode, which is described in Section 3.2.5.1 of Reference 2.

Auxiliarv feedwatgg AFW flow would be credited when the safety analysis value of the low-low steam generator level setpoint is reached. However, the parameter of interest for this transient has reached its limiting value before the appropriate Technical Specification response time delay has elapsed.

Therefore, no APW is actually delivered to the steam generators.

Turbine Trin The reactor trip leads to a subsequent turbine trip.

4.2 comnlete Loma Of Forced Reactor coolant Flow.

A complete loss of forced reactor coolant flow would occur if all four reactor coolant pumps tripped due to either a common mode failure or a sinmitaneous loss of power to the pump motors. The Reactor Protection System (RPS) senses an undervoltage con 31 tion at the pumps and initiates a reactor trip. The decrease in core flow which occurs prior to reactor trip causes a heatup of the Reactor Coolant System, 4-3

~

I The acceptance criteria for this analysis are to enoure that there is adeemce core cooling capability and that the pressure in the Reactor Coolant System remaine below 110% of design pressere.

The core cooling g

capability analysis demonstrates that fuel cladding integrity is main-g tained by ensuring that the minimum DNBR remains abovs the 95/95 DNER limit based on acceptable correlations.

The minimum DNDR is determined i

using the Statistical Core Design Methodology. The peak RCS pressure criterion is met through a comparison to the peak pressure results for the more limiting locked rotor transient.

In Section 4.3 of this f

report, the locked rotor event is shown to remain below 110% of the RCS l

design pressure.

E l

4.2.1 Nodalization Since the complete loss of flow transient is symmetrical with respect to the four reactor coolant loops, a single & p model (Reference 2, l

Section 3.2) is utilized for this analysi.

up 4.2.2 Initial Conditions core Power Level High initial power level maximizes the primary system heat flux. The uncertainty in this paraatter is accounted for in the Statistical Core I

l Design Methodology.

Pressurizer Pressure m

l Nominal full power pressurizer pressure is assumed.

The uncertainty in this parameter is accounted for in the Statistical Core Design g

Methodology, g

j Pressurizer Level I

Low initial level increases the volume of the pressurizer steam space l

which minimizes the pressure increase resulting from the insurge.

Reactor Vessel Averace Temneratur,g Nominal full power vessel average temperature is assumed. The l

ancertainty in this parameter is accounted for in the Statistical Core l

Design Methodology.

RCS Flow l

Minimum measured Reactor Coolant System flow is assumed. The i

uncertainty in this parameter is accounted for in the Statistical Core l

Design Methodology.

1 avosss Flow E

The nominal calculated flow corresponding to full power operation is 3

assumed, with the flow uncertainty accounted for in the Statistical Core Des gn Methodology.

Steam Generator Level Initial steam generator level is not an important parameter in this analysis.

4-4

1 l

Fuel Temnerature A high initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequunt transient. A low gap conductivity minimizes the transient change in fuel rod surface heat flux associated with a power decrease. This makes the power decrease less severe and is therefore conservative for DNBR evaluation.

Sigam Generator Tube Pluacina For transients of such short duration, steam generator tube plugging does not have an effect on the transient results.

4.2.3 Doundary Conditions RcP Oneration All four reactor coolant pumps are tripped at the initiation of the transient.

The pump model is adjusted such that the resulting coastdown flow is conservative with respect to the flow coastdown test data.

Steam Line safetv Valves The main steam code safety valves are modeled with opening and closing characteristics which maximize secondary side pressure and minimize primary-to-secondary heat transf er.

4.2.4 Control, Protection. and Safeguards System Modeling ggaetor Trin Reactor trip occurs on reactor coolant pump undervoltage, after an appropriate instrumentation delay.

Prennurizer Preneure control Pressurizer sprays and PORVs are assumed to be operable in order to minimize the system pressure throughout the transient.

Pressurirer Level control Pressurizer heaters are assumed to be inoperable so that Reactor Coolant System pressure is minimized. Charging / letdown has negligible impact.

Steam Line PORVs and condenter Steam Dumn

- Secondary steam relief via the steam line PORVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat transfer.

Steam Generator Level control The results of this transient are not sensitive to the mode of steam generator level control as long as the level is kept within the range that avoids protection or safeguards actuation.

MFW Pumn Seced control

' The.results of this transient are not sensitive to the mode of MFW pump speed control as long as the steam generator level is kept within the range that avoids protection or safeguards actuation.

4-5 1

3 y

v.-.--,

.m4

,,-.i, c

I P.od control No credit is taken for the operation of the Rod Control System for this transient, which results in an increase in RCS temperature.

With the Rod Control System in automatic, the control rodh would cause a negative reactivity addition as they are inserted in an ar. tempt to maintain RCS temperature at its nominal value.

Turbine control The turbine is mcteled in the load control mode, which is described in Section 3.2.5.1 of Reference 2.

hxiliarv Feedwater AFW flow would be credited when the safety analysis value of the low-low steam generator level setpoint is reached.

However, the parameter of interent for this transient has reached its limiting value before the appropriate Technica) Specification response time delay has elapsed.

Therefore, no AFW is actually delivered to the steam generators.

Turbine Trh The reactor trip leads to a subsequent turbine trip.

4.3 E2 actor coolant Pumn Locked Roter The postulated accident involves the instantanecus seizure of one reactor coolant pump rotor. Coolant flow in that loop is rapidly reduced, causing the Reactor Ptotection System (RPt.) to initiate a E

reactor trip on low RCS loop flow. The mismatch betwaen power generation 5

and heat removal capacity due to the degraded flow cos.dition causes 4 heatup of the primary system.

The acceptance criteria for this analysis are to ensure that there is adequate core cooling capability and that the pressure in the Reactor Coolant System remains below 110% of design pressure.

Peak RCS pressure and core cooling capability are analyzed separately due to the differences in assumptions required for a conservative analysis.

The core cooling capability analysis determines to what extent fuel cladding g

integrity is compromised by calculating the number of fuel rods that g

exceed the 95/95 DNBR limit based on acceptable correlations.

4.3.1 Peak RCS Pressure Analysis 4.3.1.1 Nodalization Due to the asymmetry of the transient, a two-loop model (Reference 2, Section 3.2), with a faulted single loop and an intact triple loop, is utilized for this analysis.

I I

4-6

l l

4.3.1.2 Initial Conditions core Power Level High initial power level and a positive power uncertainty maximize the l

primary system heat load.

Preneurirer Pressurg l

High initial pressure yields a analler nargin to overpressurization.

1 Preneurizer Level High initial level decreases the volume of the pressurizer steam space which maximizes the pressure increase resulting from the insurge.

Beactor Vennel Averaae Temnerature High initial temperature maximizes the initial primary coolant stored ener gy, which maximizes the transient primary pressure response.

Rcs Flow Low initial flow minimizes the primary-to-secondary heat transfer.

core nynamn rior liigh core bypass flow minimizes coolant flow through the core and exacerbates heatup.

Steam Generator Level Initial steam generator level is not an important parameter in this

analysis, Fuel Temnerature A high initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequent transient.

A low gap conductivity minimizes the transient change in fuel rod surface heat flux associa;Sd with a power decrease. This makes the power decrease less severe and thus maximizes primary pressure.

Steam Generator Pube Pluccina For transients of such short duration, steam generator tube plugging doer not have an effect on the transient results.

4.3.1.3 Boundary conditions Reactor coolant Pumns The rotor of the reactor coolant pump in the faulted loop is assumed to seize at the initiation of the transient. The remaining reactor coolant pumps trip on bus undervoltage following the loss of of f site power.

Offsite Powet Offsite power is assumed to be lort coincident with the turbine trip, Prennurizer Safetv Valven The pressurizer safety valves are modeled with opening and closing characteristics which maximize pressurizer pressure.

4-7

I' Steam Line Safetv Valves The main steam code safety valves are modeled with opening and closing characteristics which maximize secondary side pressure and minimize primary-to-secondary heat transfer.

4.3.1.4 control, Protection, and Safeguards System Modeling Reactor Trio Reactor trip occurs on low Reactor Coolant System flow in the locked loop.

Preneurizer Prerzure Control In order to maximize primary system pressure, no credit f.s taken for pressurizer spray or PORV operation.

Pressurizer _,Lpvel Control l

Pressurizer heaters are assumed to be operable in order to maximize W

Reactor Coolant System pressure resulting from the insurge/ level increase. Charging / letdown has negligible impact.

Steam Line PORVs and Condenser Steam Dumn Secondary steam relief via the steam line PORVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat transfer.

Steam Generator Level Control The results of this transient are not sensitive to the mode of steam E

generator level control as long as the level is kept within the range that avoids protection or safeguards actuation.

MFW Pumn Spged Control The results of thir transient are not sensitive to the mode of MFW pump speed control as 1 sg as the steam generator level is kept within the l

range that avoids protection or safeguards actuation, u

Rod Control g

No credit is taken for the operation of the Rod Control System for this g

transient, which results in an increase in RCS temperature. With the Rod Control System in automatic, the control rods would cause a negative reactivity addition as they are inserted in an attempt to maintain RCS temperature at its nominal value.

Turbine control h

The turbine is rodeled in the load control mode, which is described in E

Seceion 3.2.5.1 of Reference 2.

Auxillarv Feedwater AFW flow would be credited when the safety analysis value ot the low-low steam generator level setpoint is reached.

However, the parameter of interest for this transient has reached its limiting value before the appropriate Technical Specification response time delay has elapsed.

Therefore, no AFW is actually delivered to the steam generators.

I 4-8

Turbine TriD The reactor trip leads to a subsequent turbine trip.

4.3.2 Core Cooling Capability Analysis 4.3.2.1 Nodalization Due to the asymmetry of the transient, a two-loop model (Reference 2, Section 3.2), with a single (faulted) loop and a triple (intact) loop, is utilized for this analysis.

I 4.3.2.2 Initial Conditions Core Power Level High initial power level maximizes the primary system heat flux.

The l

l uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

Pressurirer prescure The nominal pressure corresponding to full power operation is assumed, with the pressure initial condition uncertainty accounted for the in Statistical Core Design Methodology.

Pressurizer Level Low initial level increases the volume of the pressuriter steam space which minimizes the pressure increase resulting from the insurge.

Reactor Vessel Averace Temnerature The nominal temperature corresponding to full power operation is assumed, with the temperature initial condition uncertainty accounted for in the Statistical Core Design Methodology.

RCS Flow The Technical Specification minimum measured flow for power operation is assumed since low flow is conservetive for DNBR evaluation. The flow initial condition uncertainty is accounted for in the Statistical Core Design Methodology.

core svnass Flow The nnminal calculated flow is assumed, with the flow uncertainty accounced for in the Statistical Core Design Methodology.

Steam Generator Level Initial steam generator level is not an important parameter in this analysis.

Fuel Temnerature A high initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequent

-transient. A low gap conductivity minimites the transient change in fuel rod surface heat flux associated with a power decrease. This makes 4-9

Il I

the pcwer decrease less severe and is therefore conservative for DNBR evaluation.

Steam Generator Tube Pluccing For transients of such short duration, steam generator tube plugging does not have an effect on the transient results.

I 4.3.2.3 Boundary Conditions Eeac ar coolant Pumns Th, rotor of the reactor coolant pump in the faulted loop is assumed to seize ist the initiation of the transient.

The remaining reactor coulant pumps trip on bus undervoltage following the loss of offsite power.

Minitp - Power cases with offsite oower maintained as well as with offsite power lost l

coincident with the turbine trip are analyzed.

W Erescu11rer Safetv Valves The pressurizer safety valves are not challenged by this transient.

Steam Line Safetv Valves The main steam code safety valves are modeled with opening and closing characteristics which maximize secondary side pressure and minimize primary-to-secondary heat transfer.

I 4.3.2.4 Control, Protection, and Safeguards System Mode ling Reactor Trin Reactor trip occurs on low Reactor Coolant System t.ow in the loop with the locked rotor.

Pressuriggr Pressure control Credit la taken for both pressurizer spray and PORV operation in order to minimize primary system pressure.

Pressuriter Level control Pressurizer heaters are assumed to be inoperable so that Reactor Coolant System pressure is minimized. Charging / letdown has negligible impact.

Steam Linn PORVs and condenser Steam Dumn Secondary steam relief via the steam line PORVs and the condenser ste a dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat trar fer.

Steam Gengrator Level control The results of this transient are not sensitive to the mode of steam generator tevel control as long as the level is kept within the range that avoida protection or safeguards actuation.

I 4-10

MFW Pumo foced control The results of this transient are not sensitive to the mode of MFW pump speed control as long as the steam generator level is kepe within the range that avoids protection or safeguards actuation.

Rod centrol No credit is taken for the operation of the Rod Control System for this transient, which results in an increase in RCS temperature.

With the Rod Control System in automatic, the control rods would cause a negative reactivity addition as they are inserted in an attempt to maintain RCS temperature at its nominal value.

Turbine control The turbine is modeled in the load control mode, which is described in Section 3.2.5.1 of Reference 2.

Auxiliary Feedwater AFW flow would be credited when the safety analysis value of the low-low steam generator level setpoint is reached.

However, the parameter of interest for this transient has reached its limiting value before the appropriate Technical Specification re inse time delay has elapsed.

Therefore, no AFW is actually delivered to the steam generators.

Turbine Trin The reactor trip leads to a subsequent turbine trip.

4.3.2.5 other Assumptions The peak clad tempetature calculation employs the fuel conduction model as described in Section 4.2.2 of Reference 1.

4-11

5.0 REACTIVITY AND POWER DISTRIBUTION ANOMALIES l

5.1 Uncontro11cd nank withdrawai prom a suberitical or Low Power

$1Artun conditiCD A malfunction of the nod Control System can result in an uncontrolled withdrawal of control rods.

Beginning from a low initial power typical of Modes 2 and 3, the resulting positive reactivity addition causes a power excursion which is terminated by the high power range flux (Iow setpoint) or high pressurizer pressure RPS trip functions.

Since the initial condition requires as few as three reactor coolant pumps in l

operation, the minimum DNBR is of concern for peak transient power

}

1evels less than full power. The peak Reactor Coolant System pressure limit of 110% of design pressure is also of concern due to the mismatch between core power and the secondary heat sink during the power excursion. Peak RCS pressure and core cooling capability are analyzed l

separately due to the differences in assumptions required for a l

conservative analysis. The core cooling capability analysis demonstrates that fuel cladding integrity is maintained by ensuring that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations.

The minimum DNBR is determined using the Statistical Core Design Methodology.

5.1.1 Peak RCS Pressure Analysis 5.1.1.1 Nodalization The peak RCS pressure transient is analyzed with four reactor coolant pumps in operation.

Since all initial and boundary conditions are symmetric, a single-loop model or any multi-loop nodalization is appropriate. The standard model (Reference 2, Section 3.2)-is used with one significant exception. Since this transient initiates at zero power, and since the duration ot the transient is very short, the steam-generator secondary response is not important.

Rather than using the standard steam generator secondary nodalization, a single secondary volume is used. The single volume uses the bubble rise option with the local-conditions heat transfer model applied to the steam generator tube conductors. With this modeling approach the initial condition of zero power can be obtained, an' the primary-to-secondary heat transfer that occurs following the power excursion can be simulated.

5.1.1.2 Initial Conditions Cg;c Power Level A minimum initial power level typical of a critical, zero power startup condition maximizes the power excursion.

Pressurirer Pressure High initial pressurizer pressure maximizes the peak-transient pressure.

5-1

I Pressurifer ley.2.1 liigh initial pressurizer level 'ninimizes the volume of the steam bubble and therefore maximizes the pressure increase following an insurge.

Reactor Vencel Averace Temnerature Reactor vessel average temperature is not an important parameter in this analysis.

RCE Flow RCS flow is not an important parameter in this analysis.

Core Dvnann Flow Core bypass flow is not an important parameter in this analysis.

Steart Generator Level Initial steam generator level is not an irnportant parameter in this analysis.

Fuel Temnerature Due to tho zero power initial condition, the initial fuel temperature is g

equal to T-ave.

The fuel-clad gap conductivity is set high to maximize g

heat transfer from the fuel, steam Generator Tube Pluacina A bounding high tube plugging value degrades primary-to-secondary heat transfer.

5.1.1.3 Boundary Conditions Non-Conductino Heat Fxchana m For initialization purposes, non-conducting heat exchangers are used to remove reactor coolant pump heat since the steam generators are passive at initialization. These are turned off prior to the start of the power excurt. ion.

=

RCP Ooeration g

Four reactor coolant pumps are in operation to increase the pressure g

drop around the loop, and to minimize thermal feedback during the power excursion.

Pressurizer Safetv Valven The pressurizer safety valves are modeled with opening and closing characteristics to maximize RCS pressure during the transient.

Steam Line Safetv Valves Although not important for this transient, steam line safety valves are g

modeled with opening and closing characteristics to minimize primary-to-g secondary heat transfer.

I 5-2

I 5.1.1.4 control, Protection, and Safeguards System Modeling f

Reacter Trin The pertinent reactor trip functions are the high power range flux (low setpoint) and pressurizer high pressure.

The high power range flux (Iow setpoint) trip includes a conservative allowance to account for calibration error, and error due to rod withdtawal effects. The response time of the high flux trip function is the Technical Specification value.

The response time of the pressurizer high pressuro trip function is the Technical Specification'value.

Since the pressure uncertainty is accounted for in the initial pressurizer precsure, the pressurizer high pressure reactor trip setpoint is the Technical Specification value.

Preneurifer Pressure control Pressurizer spray and PORVs are inoperable to maximize RCS pressure during the transient.

Preneurire Level control Due to the short duration of this transient, heaters, makeup and letdown are uniraportant.

i l

Steam Line PORVe and condenner Steam Dumn Steam line PORVs and steam dump to condenser are unimportant for this transient and are inoperable.

5.1.2 Core cooling capability Analysis 5.1.2.1 Nodalization The core cooling capability analysis, which determines the minimum DNBR, is analyzed with three reactor coolant pumps in operation. A two-loop model with one single loop and one triple loop is utilized for this analysis. The standard model (Refertnce 2, Section 3.2) is used with one significant exception. Since this transient initiates at zero power, and since the duration of the transient is very short, the steam generator secondary response is not important.

Rather than using the standard steam generator secondary nodalization, a single secondary volume is used. The single volume uses the bubble rise option with the local-conditions heat transfer model applied to the steam generator tube conductors. With this'modeling approsch the initial condition of zero power can be obtained, and the primary-to-secondary heat transfer that occurs following the power excursion can be simulated. No main or auxiliary feedwater or initial steam flow is modeled.

5-3 j

5.1.2.2 Initial Conditions Core Power Level A minimum initial power level typical of a critical, zero power startup condition maximizes the power excursion.

Egesnurizer Pressure Nominal pressure is assumed, with the pressure initial condition

=

uncertainty accounted for in the Statistical Core Design Methodology.

Pressur3rer Level Low initial pressurizer level minimizes the pressure increase following an insurge.

Reactor Vessel Averace Temneratur.e The nominal tenperature ;orresponding to zero power operation is asouzaed, with the temperature initial condition uncertainty accounted l

for in the Statistical Core Design Methodology.

EB RCS Flow Nominal three pump flow is assumed since low flow is conservative for g

DNBR evaluation.

The flow initial condition uncertainty is accounted for in the Statistical Core Design Methodology.

)

Core Dynass Fl ojg l

The nominal calculated flow is assumed, with the flow uncertainty accounted for in the Statistiet.1 Core Design Methodology.

R eam Generator Level Initial steam generator level is not an important parameter in this analysis.

Fuel Tomnerature Due to the initial zero power condition, the initial fuel temperature is equal to T-ave.

The fuel-clad gap conductivity is set high to maximize

=

heat transfer from the fuel.

Steam Generator Tube Pluacina No tube plugging is assumed to maximize the RCS volume and thereby minimize the insurge into the pressurizer.

5.1.2.3 Boundary Conditions Non-Conductina Heat Exchancers For initialization purposes, non-conducting heat exchangers are used to remove reactor coolant pump heat since the steam generators are passive g

at initialization. These are turned off prior to the start of the power 3

excursion.

I I

5-4

RCP Onaration Since low flow is conservative for DNBR, the minimum number of reactor coolant pumps (three) _ required for_the modet for which this transient is

-applicable (Modes 2 and 3) are assumed to be in operation.

Premmurizer Enfatv Valv?m The pressurizer safety valves are modeled with opening and closing characteristics to minimize RCS pressure-during-the transient.

stamm Line Enferv Valvaa l

Although not-important for this transient, steam line safety valves are modeled with opening and closing characteristics:to maximize primary-to--

secondary heat transfer.

5.1.2.4 control, Protection, and Safeguards System Modeling Rasetor trin The pertinent reactor trip functions are the high power range flux (low setpoint) and pressurizer high Pressure.

The high power range flux (low setpoint) trip includes a conservative allowance to eccount for calibration error, and error due to rod withdrawal effects.

The response time of the high flux trip function is the Technical Specification value.

The response time of the pressurizer high pressure trip function is the Technical Specification vulue. The pressurizer high pressure reactor trip setpoint is the-Technical Specification value plus an allowanee which bounds the_ instrument uncertainty.

Premmerizar Preneure control Pressurizer spray and PORVs are operable to minimize RCS pressure during the transient. -Heaters are not energized during-the transient.-

Steam Line PORVs and condanmar stamm Dumn Steam line PORVs and steam dump to condenser are unimportant for this transient and are inoperable.

5.1.2.5-Other Assumptions

-Due to the potential for bottom-peaked power distributions _during this transient, and due to the non-applicability of the Statistical core Design Methodology below the mixing vane grids in'the current fuel assembly designs, acceptable DNBRs are confirmed with the W-3S CHF

. correlation as necessary.

Explicit accounting for uncertainties (i.e.,

.non-SCD)=is used with the'W-3S correlation, i

5-5

5.2 IJngentrolled Bank Withdrawal at Power The uncontrolled bank withdrawal at poser accident is characterized by g

an increase in core power level that cannot be matched by the secondary g

heat sink. The resultant mismatch causes an increase in primary and secondary system temperatures and pressures.

The increases in power and temperature, along with a change in the core power distribution, present a DNBR concern. The primary and secondary overpressure limits of 110%

of design pressure are also of concern.

Peak RCS pressure and core cooling capability are analyzed separately due to the differences in assumptions required for a conservative analysia.

The core cooling capability analysis demonstrates that fuel g

cladding integrity is maintained by ensuring that the minimum DNBR g

remains above the 95/95 DNBR limit based on acceptable correlations.

The minimum DNBR is determined using the Statistical Core Design Methodology.

5.2.1 Peak RCS Pressure Analysis 5.2.1.1 Nodalization Since the transient response of the uncontrolled bank withdrawal event is the same for all loops, the single-loop model described in Section 3.2 of Reference 2 is utilized for this analysis.

5.2.1.2 Initial Conditions core Power Level Initial pressurizer pressure and, thus, initia margin to the overpressurization limit are independent of initial power level.

Due to the pressure overshoot during the reactor trip instrumentation delay, maximum pressure is achieved with the maximum pressurization rate.

The maximum pressurization rate is achieved with the maximum insertion of reactivity, provided that reactor trip on high flux does not occur prior to significant system heatup.

Since the initial nargin to the high flux reactor trip is greatest at a low power level, this power level yields the most rapid insertion of reactivity with significant system heatup.

Pressurirer Pressung Initial pressurizer pressure is the nominal value, and the uncertaint) in pressure is accounted for in the hige pressura reactor trip setpoint.

Ergsgarizer Lev Q g

High initial level minimizes the initial volume of the pressurizer steam E

space, which maximizes the transient primary pressure response.

EcActor Vessel Averace Temneraturg Initial temperature is not an important parameter in this analysis.

5-6

Rc2 Flow Initial RCS flow rate is not an important parameter in this analysis, core Bvnmaa Flow Core bypass flow is not an important parameter in this analysis.

Et=== canarator Laval Initial steam generator level is not an important parameter in this analysis.

Fuel Tamnaratura Low fuel temperature, associated with high gap conductivity, maximizes the transient heat transfer from the fuel to the coolant.

I Steam. Generator Tuba Pluanina A bounding high tube plugging value degrades primary-to-secondary heat j

. transfer.

l.

5.2.1.3 Boundary Conditions I

Praamurirar safetv Valvam

)

The pressurizer safety valves are modeled with opening and closing

}

characteristics which maximize the pressurizer pressure.

Steam Line Enfatv Valvaa l

I The steam line safety valves are modeled with opening and closing characteristics which maximize transient secondary side pressure and minimize transient primary-to-secondary heat transfer, b

r 5.2.1.4 control Protection, and Safeguards System Modeling Eaarter Trig The pertinent reactor trip functions are the overtemperature AT (OTAT).

g

-overpower AT'(oPAT). pressurizer high pressure and power range high flux thigh'setpoint).

L The response time of each of the two AT trip. functions is the Technical Specification value. The setpoint values of-the'AT trip funccions are continuously computed from system parameters using the modeling

(.

described'in Section 3.2 of Reference 2.

In addition, the AT coeffi-cients-used in the analysis account for instrument uncertainties.

I

'The response time of the pressurizer high pressure' trip function is the l

Technical Specification value.

The pressurizer high pressure reactor

. trip setpoint is the Technical Specification value plus an allowance which bounds the instrument uncertainty

'The' response time of the power range high flux trip function is the Technical Specification value.- The power range high flux trip high setpoint is the Technical Specification:value plus an allowance which 5-7

I i

bounds the instrument uncertainty. The high flux signal is adjusted to account for the effects of bank withdrawal.

Preneuriter Pressure control In order to maximize primary system pressure, no credit is taken for pressurizer spray or PORV operation.

Pressurizer Level control Pressurizer level control system operation has negligible impact on the results of this analysis.

Eteam Line PORVs and condenser Steam Dumn Secondary steam relief via the steam line PORVs and the condenser steam 3

dump is unavailable in order to maximize secondary side pressurization g

and minimize transient primary-to-secondary heat transfer.

)

Eteam Generator Level control Feedwater control is in automatic to prevent steam generator low-low

=

level reactor trip.

Turnine control The turbine is modeled in the load control mode, which is described in Section 3.2.5.1 of Reference '.

Auxiliar*r Feedwater Auxiliary feedwater is disabled. The addition of subcooled auxiliary l

feedwater would tend to subcool the water in the steam generator, and provide better heat removal capability.

E Turbine Trin Turbine trip upon reactor trip is modeled in order to minimize the post-trip primary-to-seconde.ry heat transfer.

5.2.2 Core Cooling Capability Analysis 5,2.2.1 Nodalization Since the transient response of the uncontrolled bank withdrawal event g

is the same for all loops, the single-loop model described in Section g

3.2 of Reference 2 is utilized for this analysis.

5.2.2.2 Initial Conditions Core Power Level g

The uncontrolled bank withdrawal event is analyzed with a spectrum of M

initial power levels which range from low power to full power.

Uncertainties in initial power level are accounted for in the Statistical Core Design Methodology.

I 5-8

l Preneurirer Pressure Initial preusurizer pressure is the nominal value, and the uncertainty in pressure is accounted for in the Statistical Core Design Methodology.

2/emeuriter Level Initial pressurizer level is the nominal value which corresponds to the initial power level, and uncertainties are accounted for in the initial value.

Low initial level maximizes the initial volume of the i'

pressurizer steam space,_which minimizes the transient primary pressure response.

Reactor Vemmel Avernae Temnerature The nominal temperature corresponding to the initial power level is 3Jsumed, with the temperature initial condition uncertainty accounted for in the Statistical Core Design Methodology.

Rcs Plog The Technical Specification minimum measured flow for power operation is assumed since low flow is conservative for DNBR evaluation. The flow initial condition uncertainty is accounted for in the Statistical Core Design Methodology.

Core Dynass Flow The nominal calculated flow is assumed, with the flow uncertainty accounted for in the Statistical Core Design Methodology.

Steam Generator Level Initial steam generator level is not an important parameter in this analysis.

Fuel TamocIAture Initial f uel temperature is the value which corresponds to the initial power level.

Low fuel temperature maximizes the transient heat transfer from the fuel to the coolant.

Steam Generator tube Pluccina The bounding tube plugging assumption (high or low) varies depending on other initial and boundary conditions.

5.2.2.3 Boundary conditions preneurizer Safetv Valvem The pressurizer safety valves are modeled with opening and closing characteristics which minimize the pressurizer pressure.

Steam Line Safetv Valven The steam lito spfety v.1ves are modeled with opening and closing characteristics which~.naximize' transient secondary side pressure and minimize transient,

4 mar)-;, secondary heat transfer.

5-9

5.2.2.4 control, Protection, and Safeguards System Modeling Reactor Trip The pertinent reactor trip functions are the overtemperature AT (OTAT),

overpower AT (OPAT). pressurizer high pressure and power range high flux (high setpoint).

The respoase time of each of the two AT trip functions is the Technical Specification value.

The setpoint values of the AT trip functions are continuously cornputed from system parameters using the modeling described in Section 3.2 of Reference 2.

In addition, the AT coeffi-cients used in the analysis account for instrument uncertainties.

The response time of the pressurizer high pressure trip function is the Technical Specification value. The pressurizer high pressure reactor trip setpoint is the Technical ~pecification value plus an allowance which bounds the instrument uncertainty.

The responoe time of the power range high flux trip function is the Technical Specification value. The power range high flux trip high setpoint is the Technical Specification value plus an allowance which bounds the instrument uncertainty. The high flux signal is adjusted to account for the effects of bank withdrawal.

Prossurirer Pressure control A sensitivity study is performed on pressurizer pressure control. Two modes are analyzed, one in which pressurizer pressure control is in 3

manual with sprays and PORVs disabled, and the other ir. which pressur-g irer pressure control is in automatic with sprays and PORVs enabled, py,gsgurizer Level control Pressurizer level control is in manual.

Level control has negligible E

impact on the results of this analysis.

Steam Line ponvs and condonner steam Dumn Secondary steam relief via the steam line PORVs and tbo condenser steam dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-seconde.ry heat transfer.

Steam Generator Level control Feedwater control is in automatic to prevent steam generator low-los level reactor trip.

Turbine conttal The turbine is modeled in the load control mode, which is described in Section 3.2.5.1 of Reference 2.

Aux 111arv Feedwater Auxiliary feedwater is disabled. The addition of subcooled auxiliary feedwater would send to subcool the water in the steam generator, and provide batter heat removal capability.

I 5-10

Turbine Trin Turbine trip upon reactor trip is modeled in order to minimize the post-trip primary-to-secondary heat transfer.

5.3 control Rod Minoneration (Statically Mina11oned Rodi The statically misaligned rod event considers the situation where a control rod is misaligned from the remainder of its bank. A rod misalignment may produce an increase in core peaking which decreases the margin to DNB.

Steady-state three-dimensional power peaking analyses are performed to confirm that the asymmetric power distributions resulting from the rod misalignment will not result in DNB.

There is no system transient associated with the analysis of the statically misaligned rod case.

The reactor is assumed to remein at its initial power level.

The statically misaligned rod evaluation is performed at nominal hat full power (HFP) conditions. Axial shapes allowed by the power dependent AFD limits are considered in the evaluation.

Two specific cases are analyzed which characterize the worst case misalignments.

The first case considers the full insertion of any one rod with Contc.< Bank D positioned anywhere within the full power rod insertion limits (RILs).

The second case considers the misalignment of a single Control Bank D rod at its fully withdrawn position, with the remainder of Control Bank positioned at the full power rod insertion limit, Power distributions resulting from case 1 are not analyzed for each reload core. Thin is because the thermal conditions (reactor power, pressure and coolant temperature) and power distributions evaluated in the dropped rod transient analysis bound the thermal conditions and power distributions that would occur in the statically misaligned rod event described in case 1. The asymmetric power distributions resulting from case 2 are evaluated for each reload core to ensure that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations. The minimum DNBR is determined using the Statistical Core Design Methodology.

The peak linear heat generation rate produced from the rod misalignment is confirmed for each reload core to be less than the linear heat generation rate which would result in fuel melt.

The peak linear heat generation rates resulting from rod misalignments do not challenge the fuel melt limit.

5.4 control Rod Minoneration (Sinale Rod Withdrawal)

The single rod withdrawal accident is characterized by an increase in the power generation of the primary system, and since the heat removal capability of the secondary system is not increased during the tran-sient, the resultant power mismatch causes an increase in primary and secondary system temperature and pressure.

=-

5-11

I The acceptance criterion for this event is to ensure that there is adequate core cooling capability. The core cooling capability analysis determines to what extent fuel cladding integrity is compromised by calculating the number of fuel rods that exceed the 95/95 DhM limit based on acceptable correlations.

5.4.1 Nodalization 85 Since the transient response of the single rod withdrawal event is the 3

same for all loops, the single-loop model described in Section 3.2 of E

Reference 2 is utilized for this analysis.

5.4.2 Initial conditions Core Power Level Initial power is the nominal full power value. Uncertainty in power W

1evel is accounted for in the Statistical Core Design Methodology.

M anurizer Prennure Initial pressurizer pressure is the nominal value. Uncertainty in pressure is accounted for in the Statistical Core Design Methodology.

Pressurizer Level High initial level minimizes the initial volume of the pressurizer steam space, which maximizes the transient primary pressure response. Up to the limit of the ability of the pressurizer sprays to controi pressure, maximum pressure is conservative in order to delay reactor trip on OT.iT.

Reactor Vercel Averace Temnerature Initial temperature is the full power nominal value. Uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

RCS Flog g

The Technical Specification minimum measured flow for power operation is g

assumed since low flow is conservative for DNBR evaluation.

The flow initial condition uncertainty is accounted for in the Statistical Core g

Design Methodology, g

core Dvnaan Flow The nominal calculated flow is assumed, with the flow uncertainty accounted for in the Statistical Core Design Methodology.

EleA*n Gengrator Level g

Initial steam generator level is not an important parameter in this 3

analysis.

Fuel Temnerature 1,ow fuel temperature, associated with high gap conductivity, maxiraizes the transient heat transfer from the fuel to the coolant.

I 5-12

Steam Generator Pube Pluacina Steam generator tube plugging is not an important parameter in this analysis.

3.4.3 Boundary Conditions Preneurifer Safety _ Valves The pressurizer safety valves are modeled with opening and closing characteristics which minimize the pressurizer pressure.

Steam Line Safety Valves The steam line afety valves are modeled with opening and closing characteristics which maximize transient secondary side pressure and minimize transient primary-to-secondary heat transfer.

5.4.4 Control, Protection, and Safeguards System Modeling Reactor Trin The pertinent reactor trip functions are the overtemperature AT (OTAT),

overpower AT (OPAT), pressurizer high pressure and pcwer range high flux (high setpoint).

The response time of each of the two AT trip functions is the Technical Specification value. The setpoint values of the AT trip functions are continuously computed from system parameters using the modeling described in Section 3.2 of Reference 2.

In addition, the AT coeffi-cients used in the analysis account for instrument uncertalaties:

The response time of the t.;ssurizer high pressure trip function is the Technical Specification value.

The pressurizer high pressure reactor trip setpoint is the Technical Specification value plus an allowance which bounds the instrument uncertainty.

The response time of the power range high flux trip function is the Technical Specification value.

The power range high flux trip high setpoint is the Technical Specification value plus an allowance which bounds the instrument uncertainty. The high flux signal is adjusted to accoun*. for the effects of rod withdrawal.

Pressurirer Pressure control Pressurizer pressure control is in automatic with sprays enabled and PORVs disabled in order to delay reactor trip on OTAT and delay reactor trip on high pressurizul pressure.

Pressurizer Level control Pressurizer level control is in manual with the pressurizer heaters disabled in order to delay reactor trip on high pressurizer pressure.

Charging / letdown has negligible impact.

5-13

I Steam Line PORVs and condenser Steam DuCD Secondary steam relief via the steam line PCRVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization g

and minimize transient primary-to-secondary heat transf er, g

Steam Generator Level control Feedwater control is in automatic to prevent steam generator low-low level reactor trip.

Aux 111arv FeedWatar l

Auxiliary feedwater is disabled.

The addition of subcooled auxiliary N

feedwater would tend to subcool the water in the steam generator, and reduce secondary side pressure.

Turbine control The turbine is modeled in the load control mode, which is described in Section 3.2.5.1 of Reference 2.

Turbino Trin Turbine trip upon reactor trip is modeled in order to minimite the post-E trip primary-to-secondary heat transfer.

B 5.5 Startun of An inactive Reactor coolant Pumn At An Incorrect Temnerature The McGuire and Catawba plant Technical Specifications currently require l

that all four RCPs be running at power operation.

Furthermore, low flow W

in any RCS loop, coincident with reactor power above the P-8 interlock (currently at 48% of rated thernal power) will cause a reactor trip.

Therefore, the only situation in which the subject accident is possible is a trip of one RCP below P-8.

For this situation the operator might choose, during allowable at power outage time for the fourth RC?, to attempt a restart of the tripped pump. The accident is analyzed from the most conservative condition allowed by the Reactor Protection System, even though operator error is required for the analyzed scenario to occur. The acceptance criterion is that. fuel cladding integrity shall be maintained by ensuring that the minimum DNBR remains the above the 95/95 DNBR limit based on acceptable correlations.

5.5.1 Nodalization Decause of the loop asymmetry between the inactive single loop and the l

three active loops, the doub2ez-loop kCS model described in Section 3.2 W

of Reference 2 is used.

5.5.2 Initial Conditions Core Power The inadvertent pump startup event is analyzed assuming that the plant administrative procedure (i.e.,

lowering the power level to 25% of rated thermal power prior to starting the idle pump) is not followed. Thus, 1

5-14

it is assumed that the plant is operating at the P-8 setpoint of 48% of rated thermal pown plus a positive power uncertainty.

Preneurizer Prensure A pressure initial condition uncertainty including a bias is applied to miniinite pressure during the transient since this is conservative for DNBR evaluation.

Pressurirer Level The heatup of the colder water and the increase in core power will cause an expansion of the reactor coolant and an increase in pressurizer level. A negative level uncertainty is used in order to maximize the size of the pressurizer steam bubble to be compressed, which minimizes the transient pressure response.

Reactor Vessel Averaae Temnerature A positive temperaturn uncertainty is used to minimize the margin to DNB.

RCS Flog In order to minimize core flow, and therefore the margin to DNB, the three pump equivalent of the Technical Specification minimum measured i

flo is adjusted by a negative flow uncertainty.

Care Dvnans Flow High core bypass flow minimizes coolant flow through the core and therefore minimizes the margin to DNB.

Steam Generator Level The results of this transient are not sensitive to the direction of steam generator level uncertainty as long as the transient level response is kept within the range that avoids protection or safeguards actuation.

l Egel Temneraturg A low initial temperature is assumed to maximize the gap conductivity calculated for steady-state conditions and used for the subsequent trans!ent. A high gap conductivity minimizes the fuel heatup and attendant negative reactivity insertion caused by the power increase.

This makes the power increase more severe and is therefore conservative for DNB ovaluation.

SLgam Generator Tube Pluccina Ste m generator tube plugging is not an important parameter in this analysis.

5.5.3 Boundary Conditions RCP Occration The RCP9 operating prior to the accident are modeled assuming constant speed operation throughout the transient. The RCP that is inactive at the start of the accident is modeled with a conservative speed vs. time controller.

5-15

I 5.5.4 Control, Protection, and Safeguards Systems Modeling Reactor Trin The reactor trip on low RCS flow coincident with reactor power above the 3

P-8 interlock is conservatively assumed to be unavailable.

Pressurizer Pressure control The pressurizer sprays and PORVs are assumed to be operable to minimize the pressure increase resulting from the pump restart and power increase.

Pressurifer Level control No credit is taken for pressurizer heater operation to compensate for g

the increase above programmed pressurizer level which occurs due to the 3

power increase.

Heater operation would tend to elevate pressure.

Steam Generator Level control The results of this transient are not sensitive to the mode of steam generator level control as long as the steam generator level is kept within the range that avoids protection or safeguards actuation.

MFW Pumn Sneed control The results of this transient are not sensitive to the mode of MFW pump speed control as long as the steam generator level is kept within the range that avoids protection or safeguards actuation.

Rod control The Rod Control System is assumed to be in automatic when reactor vessel average temperature decreases.

The temperature decrease will cause rod withdrawal and an increase in core power.

Turbine control The turbine is assumed to be in manual control.

In this mode, the valves do not respond to changes in steam line pressure.

Therefore, when steam line pressure incret es due to increased hert input from the primary system, the steam flew.o the turbine will increase. This will retard the core power 2ess than if the turbine control valves closed l

down and caused steam line pressure and RCS temperatures to increase 5

turther, hurillarv Feedwater AFW flow would be credited when the safety analysis value of the low-low steam generator level setpoint is reached.

However, the parameter of interest for this transient has reached its limiting value before the appropriate Technical Specification response time delay has elapsed.

Therefore, no AFW is actually delivered to the steam generators.

5.6 CVCs Ms1 function That Results In A Decrease In_ Boron concen-E !

tration In The Reactor coolant gI A boron dilution occurs when the soluble boric acid concentration of makeup water supplied to the RCS is less tnan the concentration of the i

existing reactor coolant. The boron dilution accident postulates that 5-16

such a dilution occurs without adequate administrative control such that there was the potential for loss of shutdov margin. This accident is conservatively analyzed to ensure tnat the di?.stion is terminated, by nenual or automatic means, within appropr' to time limits. In accordance with Reference 3, appropriate time is judred to be at least 15 minutes for Modes 3-5 and at least 30 minutes for Mode 6.

The licensing bases for the McGuire and Catawba Huclear Stations are different.

For McGuire, this accident is analyzed for the power operation (Mode 1), startup (Mode 2), and refueling (Mode 6) modes of operation. Manual operation is relied on to terminate the dilution in all three modes. For Catawba, this accident is analyzed for the power operation, startup, hot standby (Mode 3), hot shutdown (Mode 4), cold shutdown (Mode 5), and refueling modes of operation. Automatic operation of the Boron Dilution Mitigation.yster (BDMS) is relied on to termina.e the dilution in hot standby, hot shutdown, cold shutdown, and refueling, with manual operation as substitute means when the BDMS is inoperable. Manual operation is relied on to terminate the dilution in power operation or startup.

The various modes at the two stations are analyzed with two different methods for two different purposes. First, with the BDMS applicable and l

assumed to be operable, the accident is analyzed to demonstrate that there is adequate time, without restrictions on the flow rates from potential dilution sources, for the BDMS to terminate the dilution prior to criticality. This time consists of two components: 1) the period required ts stroke the valves manipulated by the BDMS and 2) the period required, once the unborated water source has been isolated, to purge the remaining unborated water from the niping leading to the RCS.

[

Second, with the BDMS inapplicable or assumed to be inoperable, the I

accident is analyzed to demonstrate that there is adequate time, possibly with restrictions on the flow rates from potential dilution sources, for the operator to terminate the dilution prior to criticality.

Since the BDMS is not used in Modes 1 and 2, the analysis of these modes is similar to the analysis of Modes 3-6 with the BDMS assumed to be inoperable, but without the restrictions on flow rates.

During Mode 6 an inadvertent dilution from the Reactor Makeup Water System is prevented by administrative controls which isolate the RCS from potential sources of unborated makeup water.

The results of the accident analysis for this mode are for an assumed dilution event, for which no mechanism or flow path has been identified.

The results of the accident analysis are for the dilution flow rates which, assuming the boron concentrations are at the reload safety analysis limits, give exactly the acceptance criteria operator response times.

Flow rates are restricted, through Technical Specifications and administrative controls, to values which are loss than these analyzed flow rates, thus in practice giving even longer operator resporse times. Additional margin is provided by the fact there is typically margin between the assumed boron concentrations for a givos mode and the actual corresponding concentrations for the reload core.

5-17 i

I 5.6.1 Initial Conditions Dilution volume g

A postulated dilution event progresses faster for smaller RCS water g

volumes, Therefore, the anaiysis considers the smallest RCS water voluts in which the unborated watwr is actively mixed by forced circulation. For Modes 1-3, the Technical Specifications require that at least one reactor coolant pump be operating.

This forced circulation will mix the RCS inventory in the reactor vessel and each of the four reactor coolant loops. The pressurizer and the pressurizer surge line are not included in the volume available for dilution in Modes 1-3.

For normal operation in Mode 4, forced circulation is typically maintained, although the Technical Specifications do not require it.

The volume available for dilution in Mode 4 is therefore conservatively assumed to not include the upper head of the reactor vessel, a region which has reduced flow in the absence of forced circulation, or the pressurizer and the pressurizer surge line. Since the Technical Specifications do require operability of all four steam generators during Mode 4, all four of the reactor coolant loops, in addition to the remainder of the reactor vessel, are included in the RCS volume available for dilution.

l For Modes 5 and 6, the reactor coolant water level may be drained to g2 below the top of the main coolant loop piping, and at least one trein of l

the Residual Heat Removal System (RHRS) is operating. The volume assilable for dilution in these modes is limited to the smaller volume RHRS train plus the porcions of the reactor vessel and reactor coolant loop piping belcw the minimum water level and between the RHRS inlet and outlet connections. The minimum water level used to calculate this l

volume is corrected for level instrument uncertainty.

W Boron Concentrationg g

The Technical Specifications require that the shutdown margin in the g

various modes be above a certain minimum value.

The difference in boron concentration, between the value at which the relevant alarm function is g

actuated and the value at which the reactor is just critical, determines g

the time available to mitigate a dilution event. Mathematically, this time is a function of the ratio of these two concentrations, where large ratio corresponds to a longer time.

During the reload safety l

analysis for each new core, the above concentrations are checked to B

ensure that the value of this ratio for each mode is larger than the corresponding ratio assumed in the accident analysis. Each mode of M

operation covers a range of temperatures. Therefore, within that mode, g

.the temperature which minimizes this retio is used for comparison with the accident analy11s ratio.

For accident initial conditions in which the control rods hre withdrawn, it is conservatively assumed, in calculating the critical boron concentration, Nat the most reactive rod

=

does not fall Juto the core at reactor trip. This assumption is also conservatively applied in Mode 3 when the initial condition is hot zero l

power.

For colder conditions in Modes 3-5, emergency procedures for E

reactor trip with a stuck rod require that, prior to the initiation of l

the cooldown, the boron concentration be increased by an amount which compensates for any rods not completely inserted.

I, 5-18 1

5.6.2 Boundary Conditions In the absence of flow rate restrictions, the dilution flow rate assumed to enter the RCS is greater than or equal to the design volumetric flow rate of both reactor makeup water pumps.

In a dilution event, these pumps arr assumed to deliver unborated water to the suction of the centrifugal charging pumps.

Cince the water delivered by these pumps la typically colder than the RCS inventory, the unborated water expands within the RCS, causing a given voluk.atric flow rate measured at the colder temperature to correspond to a larger volumetric dilution flow rate within the RCS.

This density difference in the dilution flow rate is accounted for in the analysis.

The above assumption on flow rate is also conservatively used for Mode 6.

Any makeup which is required during this mode is borated water supplied from the refueling water storage tank.

5.6.3 Control, Protection, and Safeguards System Modeling Mitigation of a boron dilution accident is not assumed to begin until an alarm has warned of the abnormal circumstances caused by the event.

For Modes 3-6 with the BDMS operable, the alarm function is provided by the measured source range count rate exceeding the BDMS setpoint.

For Modes 3-6 with the BDMS inoperable, the alarm function is provided by the source range high-flux-at-shutdown alarm exceeding its setpoint. For Mode 2 and for manual rod control during Mode 1, the alarm function is provided by the earliest reactor trip setpoint reached. Finally, ?or automatic roi control during Mode 1, the alarm function is provided by the alarm which occurs when the control rods reach their insertion limits.

5.7 Inadvertent Loadino and Oneration of A Fuel Assembly In An Imnroner Positi.)

Core loading errors can occur from the improper loading of one or more fuel assemblies in an improper position, from enrichment errors, or from the misloading or omission of burnable absorber rods. The result of these errors is the possibility that core peaking will exceed the peaking calculated for the correct core loading.

Administrative procedures are in place to prevent enrichment errors during fuel fabrication and during core loading. Also, a rigorous startup physics testing program is performed subsequent to each core loading that would detect any credible misloaded fuel assembly. The misloaded fuel assembly analysis confirms that the increase in peaking produced from a loading error or enrichment error would either be detected by the incore flux mapping system, or would be less than the peaking uncertainties included in the analysis of both Condition I and Condition II events.

\\

5-19

6.0 INCREASE IN REACTOR COOLANT INVENTORY

-6,1 Inadvertent Doeration of EccB Durina Power Doeration The inadvertent operation of-the Emergency Cors Cooling System could be caused by either operator error or a spurious electrical actuation signal. Upon receipt of the actuation signal, the centrifugal charging i

pumps begin delivering highly borated refueling water storago tank water to the Reactor Coolant System. The resultant negative reactivity incerticn causes a decrease in core power and, consequently, a decrease in temperature.

Initially, coolant chrinkage causes a reduction in both pressurizer water level and pressure.

Core cooling capability (DNB) is the nrlmary concern during this time period due to the decrease in system pressure.

Following the initial depressurization, the increase in reactor coolant inventory causes pressurizer level to increase and pressurization to occur.

Pressurizer leval might increase sufficiently to overfill the pressurizer and cause water relief through the pressurizer safety valves (Pi?s). Water relief through the PSVs could degrade valve operability an' lead to a Condition III event, the magnitude of the pressure decrease for this transient _is no more severe than that for the inadvertent opening of a pressurizer safety or relief valve transient, which also trips the renctor on low pressurizer pressure.

Furthermore, the openjng of a safety valve does not introduce the core power and Reactor Coolart System temperature decreases that are l

characteristic of the inadvertent ECCS actuation. Neither event involves any reduction Ai the Reactor Coolant System flow rate, since-the reactor coolant pum,a are not tripped. Therefore, the DNB resulta j-of this transient are bounded by the,sadvertent opening of a f'

' pressurizer safety or relief valve tr' sient.

Based on the above qualitative evaluation,

..antitative core cooling capability analysis of this transient is not required. Should a f.

reanalysis become necessary, either due to plant changes, modeling changes, or other changes which invalidate any of the above arguments, the analytical methodology employed would be as follows.

The core cooling capability analysis demonstrates that fuel cladding integrity is maintained by ensuring that the minimum DNBR remains above the 95/95 DNBR limit based on acceptable correlations, The minimum DNBR is determined using the Statistical Core Design Methodology.

The concern in the pressurizer overfill analysis is that water relief through the PSVs will degrade valve operability and lead to a Condition III event.

However, even if water relief occurs, valve operability is not degraded provided that the temperature of the pressurizer water is sufficiently high. Therefore, the acceptance criterion for this analysis is the minimum water relief temperature to assure PSV operability.

6-1 i

-__-___-__J

I 6.1.1 Core Cooling Capability Analysis 6.1.1.1 Nodalization Since the inadvertent ECCS operation transient is symmetrical with respect to the four reactor coolant loops, a single-loop model (Reference 2 Section 3.2) is utilized for this analysis.

6.1.1.2 Initial Conditions Core Power Level High initial power level maximizes the primary system heat flux.

The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

Pressuriier Pressurg

'N Nominal full power pressurizer pressure is assumed.

The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

Pressuriier I m l High initial level minimizes the volume of the pressurizer steam space which maximizes the pressure decrease resulting from the outsurge.

Reactor Vessel Averace Temnerature Nominal full power vessel average temperature is assumed. The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

RCS Flow The Technical Specification minimum measured flow for power operation is assumed since low flow is conservative for DNBR evaluation. The flow initial condition uncertainty is accounted for in the Statistical Core Design Methodology.

core Bvnass FM The nominal calculated flow is assumed, with the. flow uncertainty accounted for in the Statistical Core Design Methodology.

Steam Generator Level Steam generator level is not an important parameter in this analysis.

Puel Temnerature A high initial temperature is, assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequent h

transient. A low gap conductivity minimizes the transiert change in 3

fuel rod surf ace heat flux associat-vi th a power decrease. This makes the power decrease less severe anu

.m

.aerefore conservative for DNBR ovaluar. ion.

I 6-2

Steam Generator Pube Pluccina Steam generator tube plugging is not an important parameter in this analysis.

6.1.1.3 Boundary conditions Eccs Flow A maximum safety injection flow rate along with a conservatively high boron concentration yields the most limiting transient response.

In order to minimize the delay in the delivery of the borated injection water, no credit is taken for the purge volume of unborated water in the injection-lines.

Steam Line safetv Valven The main steam code safety valves are modeled with opening and closing characteristics which maximize secondary side pressure and minimize l

primary-to-secondary heat transfer.

6.1.1.4 Control, Protection, and Safeguards System Modeling l

Reactor Trio Reactor trip is assumed to occur on low pressurizer pressure, after an.

[

appropriate instrumentation delay.

I Pressurizer Pressure control Pressurizer sprays and PORVs are assumed to be operable in order to

.aina. ze the system pressure throughout the transient.

Pressurizer Level control Pressurizer heaters are assumed to be inoperable so that Reactor Coolant System pressure is minimized. Charging / letdown has negligible impact.

Steam Line PORVs and condenser Stesm Dumn Secondary steam relief via the steam line PORVs and the condenser steam dump is unavailable in order to maximize secondary side pressurization and minimize transient primary-to-secondary heat transfer.

Steam Generator-Level Control The results of this transient are not sensitive to the mode of steam generator levol centrol as long as the level is kept within the range that-avoids protection or safeguards actuation.

MFW Pumn Soeed control The results of this transient are not sensitive to the mode of MFW pump

-speed control as long as the steam generator level is kept within the range that avoids protection or safeguards actuation.

Rod control No credit is taken for the operati 7 of the Rod Control System for this transient, which results in a decrease in RCS temperature. With the Rod Control System in automatic, the control rods would cause a positive reactivity addition as they are withdrawn in an attempt to maintain RCS 6-3

I temperature at its nominal value.

The resultant power increase would rotard the system depressurization.

Turbine control The turbine is modeled in the load control mode, which is described in Section 3.2.5.2 of Reference 2.

Aux!11arv Feedwater AFW flow would be credited when the safety analysis value of the low-low steam generator level setpoint is reached.

However, the parameter of l

interest for this transient has reached its limitir.g value before the 5

appropriate Technical Specification response time delay has elapsed.

Therefore, no AFW is actually deli */ered to the steam generators.

Turbine Trin The reactor trip leads to a subsequent turbine trip.

I 6.1.2 Pressurizer Overfill Analysis I

6.1.2.1 Initial Conditions core Power Zero power is assumed in this analysis.

Reference 3 states that the acceptable initial power for the analysis is the licensed core thermal

power, i.e.,

full power.

However, lower power is more limiting in order l

to minimize the initial RCS temperature.

If overfill occurs at lower E

initial power, then the water relief temperature is more likely to be less than the acceptance criterion.

Pressurizer Pnssure Actual system response to a safety injection (SI) would be an initial pressure drop then subsequent pressuris.ation above initial pressure.

During the depressurization phase, SI flow would increase above the

=

initial flow rate, and during the pressurization phase. FI flow would decrease below initial flow rate.

Initial pressure is assumed conservatively low to determine the SI flow during i.he event.

Reactor Vessel Averace Temnerature Low initial temperature is conservative in. order to minimize pressurizer water temperature.

Steam Generator Tube Pluccind High steam generator tube plugging is assumed in order to decrease the E

volume of the initial RCS water, which will minimize the RCS water temperature as it mixes with the cold SI water.

6.1.2.2 Doundary conditions RCP Oneration For Modes 1-3, the Technical Specifications. squire at least one reactor coolant pump be operating.

6-4

6.1.2.3 Control, Protection, and Safeguards System Modeling Premrurizer Level Control 3

The pressurizer heaters are assumed to be in manual and off since heater operation would increase the temperature of the pressurizer water.

Normal makeup is isolated upon SI, and credit is not taken for letdown.

ECCS Flow A maximum safety injection flow rate from both centrifugal charging pumps is assumed. RCS pressure remains above the shutoff head of the intermediate head and low head safeti' injection pumps for the duration of the event.

a ECCS Temnerature Minimum injection temperature is conservative in order to minimize relief temperature, i

k L

K

• n I.

4, :

6-5

c7.0 DECREASES IN REACTOR COOLANT INVENTORY 7,1 Tnadvertent Ooenina of a PressuriTer safety or Relief Valve The-loss of. inventory through the open valve causes a depressurization of the RCS.

Since the core power, flow, and temperature are relatively unaffected prior to-reactor trip by this-depressurization,-the reduction in pressure causes a reduction in DNB margin.

The applicable

-acceptance criterion is that fuel cladding integrity shall be maintained by ensuring that the minit DNBR remains the above the 95/95 DNBR limit based on acceptable correlac.Jns.

The minimum DNBR is determined using the Statistical Core Design Methodology.

7.1.1 Nodalization Since the valvo opening is in the pressurizer, it affects all'RCS loops identically. Therefore a single-loop RCS system model is used.

7.1.2 Initial Conditions Power Level i

Full power is assumed in order to maximize the primary system heat flux.

The uncertainty in this parameter is accounted for in the Statistical Core Design-Methodology.-

PressuriTer Preneure Nominal pressure is assumed, with the pressure initial condition uncertainty accounted for in the Statistical Core Design Methodology.

PreneuriTer'Lrvel Since this accident involves a reduction in RCS volume due to' inventory 3

loss, a negative level uncertainty is assumed to minimize the initial pressurizer liquid volume and therefore' maximize the' pressure decrease

-due'to inventory loss.

Reactor Vennel Averace Tamnerature The nominal temperature corresponding to full power operation is assumed, with the temperature initial condition uncertainty accounted ifor in the Statistical Core Design Methodology.

RCS Flow The Technical' Specification minimum measured flow for power operation is assumed since low flow is conservative'for DNBR evaluation. The flow initial condition uncertainty is-accounted for.in the Statistical Cors Design Methodology.

Core Evnamn Flow The nominal calculated flow is assumed, with the flow uncertainty accounted for in the Statistical Core Design Methodology.

7-1

I Steam Generator Level The results of this transient are not sensitive to the direction of steam generator level uncertainty as long as the transient level g

response is kept within the range that avoids protection or safeguards g

actuation.

Fuel Temnerature A high initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the subsequent transient. A low gap conductivity minimizes the transient change in l

fuel rod surface heat flux associated with a power decrease due to g

moderator density.

This makes the power decrease less severe and is therefore conservative for DNBR evaluation.

Steam Generator Tube Plucaina The results of this analysis are not sensitive to the amount of steam generatcr tube plugging.

7.1.3 Boundary Conditions Steam Line Safetv Valves The results of this transient are.not sensitive to the main steam safety valve modeling as long as the opening of the safety valves occurs after reactor trip.

7.1.4 Control, Protection, and Safeguards Systems Modeling Reactor Trin Reactor trip is on either low pressurizer pressure or overtemperature AT.

The Technical Specification response times are used and the safety analysis setpoints include the effects of uncertainty in the monitored parameter and in the setpoint.

Presstrizer Pressure Control No credit is taken for pressurizer heater operation to compensate for g

the decrease in pressurizer pressure which occurs due to the inventory 3

loss. This results in a lower post-trip pressurizer pressure, which is conservative for DNBR evaluation.

Steam Generator Level Control The results of this transient are not sensitive to the mode of steam generator level control as long as the level is kept within the range that avoids protection or safeguards actuation.

4 MFW Pumn Sneed Contr E

The results of this transient are not sensitive to the mode of MFW pump E

speed control as long as the steam generator level is kept wi*.hin the range that avoids protection or safeguards actuation.

Rod Control Rod control is assumed to be in manual for this transient.

I 7-2 i

1

.. _ ~

Turbine control The turbine is nodeled in the load control mode, which is described in Section 3.2.5.1 of Reference 2.

Auxiliarv Feedwater-AFW flow would be credited when the safety analysis value of the low-low steam generator level setpoint is reached. However, the parameter of interest for this transient has reached its limiting value before the appropriate Technical Specification response time delay has elapsed.

Therefore, no AFW is actually delivered to the steam generators.

Turbine Trin The turbine is tripped on reactor trip. A conservatively long time delay is assumed since this assumption minimizes the post-trip primary pressure response.

7.2 Steam Generator Tube Runture The steam generator tube rupture analyzed is a double ended guillotine break of'a single tube. This transient is evaluated in two parts; first to evaluate minimum DNBR, and secondly to provide offsite dose input data for a separate evaluation to determine whether the fission product release to the environment is within the established dose acceptance criteria.

ThS DNBR analysis for this transient is modeled as a complete loss of coolant flow event initiated frcm an off-normal condicion, using the Statistical Core Design methodology.

The loss of flow is assumed to i.

occur subsequent to the OTAT reactor-trip caused by the steam generator tube rupture depressurization.

The initiating event for the offsite dose input analysis is the double-ended guillotine break of a single steam generator tube; This analysis generates the offsite steam release boundary condition for the dose evaluation. The single failure identified for maximizing offsite dose is the failure of the PORV on the ruptured steam generator to close. In this analysis, this valve remains open until operator action is taken to isolate the PORV.

7.2.1 Core Cooling Capability Analysis

-7.2.1.1 Nodalization Since the complete loss of flow transient is symmetrical with respect to the four reactor coolant loops, a single loop model (Reference 2,

-Section 3.2) is utilized for this analysis.

7-3

7.2.1.2 Initial Conditions care Power Levd High initial power level maximizes the primary system heat flux. The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

Pressurizer Pressure Nominal pressurizer pressure is assumed. The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

Pressurizer Level Low initial level increases the volume of the pressurizer steam space which minimizes the prer.sare increase resulting from ':.s insurge.

Egg;f g Vessel Avernae Temnerature Nominal sel average temperature is assumed. The uncertainty in this l

parameter is accounted for in the Statistical Core Design Methodology, as RCS Flow Minimum measured Reactor Coolant System flov is assumed.

The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

Core Evnass Flow Nominal ~ full power bypass flow is assumed.

The uncertainty in this parameter is accounted for in the Statistical Core Design Methodology.

l Ream C rerator Level

(

Initial steam generator level is not an important parameter in this l

analysis.

Fuel Temnerature A high initial temperature is assumed to minimize the gap conductivity calculated for steady-state conditions and used for the rubsequent

=

transient. A low gap conductivity minimizes the transir.nt change in fuel rod surface heat flux associated with a power decrease. This makes E

the power decrease less severe and is therefore conservative for DNBR

-E evaluation.

Steam Generator Tube Pluacina For transients of such short duration, steam generator tube piagging does not have an effect on the transient results, 7.2.1.3 Boundary Conditions RCP Deeration All four reactor coolant pumps are tripped on the loss of offsite power.

The pump model is adjusted such that the resulting coastdown flow is conservative with respect to the flow coastdown test data.

I 7-4 s

steam Line Safety Valves-The main steam ode safety valves are modeled with opening and closing

-characteristics which maximize secondary sido pressure and minimize

-primary-to-secondary heat transfer.

Offalte Power

-Offsite power is assumed to-be lost coincident with turbine trip in order to minimize FCS flov following reactor trip.

7.2.1.4 Control, Protection, and Safeguards Syttem Modeling Remeter Trin Reactor trip is assumed to occur on overtemperature AT, after an appropriate instrumentation delay.

Preneurizer Premnure control Following the tube rupture, RCS pressure continuously decreases through the time at which minimum DNBR occurs.

Thus, pressurizer sprays are not activated nor are the pressurizer.PORVs challenged during the transient.

I Preneurizar Level control j

Pressurizer heaters are assumed to be inoperable so that-Reactor Coolant

. System pressure is minimized.. Charging and letdown are assumed to be balanced at all times during the event with no action taken to increase charging flow due to RCS pressure and pressurizer level decreasing.

.This will maximize the RCS.depressurization rate.

Steam Line-PORVs and condenser Stamm Dumn

-The main steam PORVs and' condenser dumps valves are assumed to be

-unavailable during this transient. This maximizes the secondary side

-pressure and temperature and therefore reduces primary-to-secondary heat transfer.

Steam Generator Level control

=The.results of this transient are not sensitive to-the mode of steam-generator level control as long as the level is kept within the range that avoids protection or safeguards actuation.

MFW Pumn Sneed control The results of this transient are not sensitive to the mode of MFW pump speed controluns long as the steam generator level-is kept within the-range that avoids protection or safeguards actuation.

Rod control No credit'is taken for.the operation of the Rod Control System for this transient, which results in an increase in RCS temperature. With the

. Rod Control System in automatic, the control rods would cause a negative reactivity addition as they are inserted in an attempt to maintain RCS temperature at its nominal value.

~

7-5

iurbine control The turbine is modeled in the load control mode, which is described in Sec*. ion 3.2.5.1 of Reference 2.

Auxiliarv Feedwater AFW flow would be credited when the safety analysis value of the low-low g

steam generator level setpoint is reached. However, the parameter of g

interea for this transient has reached its limiting velue before the appropriate Technical Specification response time delay has elapsed.

Therefore, no AFW is actually delivered to the steam generators.

Turbine Trio The reactor trip leads to a subsequent turbine trip.

7.2.2 Offsite Dose Calculation Input Analysis I

7.2.2.1 Nodalization Due to the asymmetry of this transient a three-loop model, with two single loops and a double loop, is utilized for this analysis.

The bounwry conditions for the two intact steam generators with operable steam line PORVs are symmetric.

The loop with the tube rupture requires separate modeling, as does the loop with the inoperable steam line PORV.

I 7.2.2.2 Initial Conditions core Power Level High initial core power and a positive uncertainty maximize the primary system heat load.

I Pressurizer Pressurg High initial pressure with a positive uncertainty delays the time of automatic reactor trip. This retards the' primary system cooldown, l

extending primary-to-secondary leakage, and therefore maximizing the E

offsite dose.

Pressuri*gr Level High initial level with a ponitive uncertainty maximizes primary-to-secondary leakage and maximizes pressurizer haater operation.

. Reactor Vessel Averace Temnerature Nominal vessel average temperature with a negative uncertainty is used to minimize the initial steam generator steam pressure. This maximizes E

the initial differential pressure across the steam generator tubes and 3

therefore maximizes the initial primary-to-secondary leakage.

A '>wer vessel average temperature also maximizes the initial primary-to-secondary leakage.

If the reactor trip occurs at a fixed time (e.g.,

due to manual safety injection), maximizing the leakage maximizes the amount of high activity inventory leaked to the stea.: generators.

However, if an automatic reactcr trip occurs, it is because a sufficient 7-6 l

_____-._________.m__

inventoryLof primary-to-secondary leakage has occurred, and in that case the transient is not sensitive to assumptions which only change the rate of leakage.

RCS Flow Nominal primary system loop flow with a negative uncertainty is assumed..

Low forced circulation flow results in lower natural circulation flow during the post-trip cooldown.

This reduces primary-to-secondaiy heat-transfer and extends plant cooldown.

Frictional and form losses will-also be smaller throughout the RCS, resulting in a higher primary pressure at the break location. This maximizes primary to secondary.

leakage.

Core Bvnans Flow Core bypass flow is not an important parameter for this transient..

Steam Generator Level Minimum steam generator level reduces the initial secondary inventory available to mix with and dilute the primary-to-secondary leakage. This l

also minimizes the secondary side static head at the break location, l

thus maximizing primary to secondary leakage.

Enni Tamnerature High initial fuel temperature naximizes the stored energy which must be removed during the post-trip natural circulation cooldown.

Steam Generator Tube Plucaina.

-Steam generator tube plugging is aot an important parameter in thin analysis.

7.2.2.3 Boundary Conditions sinole Failure The single failure identified.for maximizing offsite dose is the failure of the PORV on the ruptured steam generator to close.

In this analysis, this valve remains open until operator action is taken to isolate the PORV.

Per Reference e, page 5-7,-'The most limiting failure would be-the-loss of air supply or power which prevents actuation of the (PORVs) from the main control room. The valves could be operated (locally) by

. manual action to correct for this single failure." This failure is incorporated into the analysis as it prolongs the transient, maximizing-the primary-to-secondary leakage.

. Pressurizer Safetv Valves The pressurizer code safety valves are not challenged during the course of this transient.

. Steam Line Safety Valves The main steam code safety valves are modoled with opening and closing characteristics which maximize secondary pressure. This delays operator identification of the failed open steam line PORV.

7-7 1

L

l 8

\\

Steam Line PORVs only two of the three steam line PORVs on the intact ateam generators are assumed to be operable. This lengthens the cooldown time, thereby maximizing the atmospheric steam releases. A negative bias is applied to the ruptured steam generator PORV control signal. This results in an earlier opening time which maximizes atmospheric releases and de.teys operator identification of the failed open steam line PORV.

A ponitive bias is applied to the intact SG PORV control signals to maximize socondary side post-trip pressurization. This delays operator identification of the failed open steam line PORV.

Decav He g End-of-cycle decay heat, based upon the ANSI /ANS-5.1-1979 standard plus a two-sioma uncertainty, is employed.

Qffsite Power offsite power is assumed to be lost coincident with turbine trip. This l

isolates steam flew to the condenser, thereby maximizing the atmospheric steam releases, g

Break Model The break is assumed to be a double-ended guillotine break of a single steam generator tube at the tuberheet surface on the steam generator outlet plenum. This location maximizes the mass flow through the break.

RCP Oneration The reactor coolant pumps are assumed to operate normally until offsite l

power is lost coincident with turbine trip.

W ECCS Iniection SI actuation is assumed to occur on low pressurizer pressure at a setpoint with an applied positive uncertainty or on manual operator action.

Maximum ECCS injection flow is assumed to maximize the primary-to-secondary leakage.

Main Feedwater Main feedwater flow is assumed to terminate coincident with the loss of I

offsite power to minimize the secondary inventory available to mix with 5

and dilute primary-to-secondary leakage.

Charoina Flow A conservatively high charging flow capacity is modeled to delay reactor trip and maximize total primary-to-secondary leakage.

Manual Actions

- Immediate action to maximize charging flow (penalty).

- Immediate action to energize presuurizer heater banks (penalty).

I

- Operators identify the abnormal condition of the RCS at 20 minutes and manually trip the reactor if not already tripped.

7-8 1

4

~ Identify and isolate ruptured steam generator consistent with assumptions'in WCAP-10698 (Reference 5), 15 minute minimum delay (credit).1

-Isolate failed openiste&m line drains upstream of the main steam 1

isolation valves. This action occurs 10 minutes-after the-ruptured steam generator is identified.

Isolate the-steam. oupply to the-turbine-driven auxiliary feedwater pump.from the. ruptured steam generator-after-identification of the ruptured steam generator. An operator action delay time of 30 minutes is assumed'-(credit).

,C Isolate failed open steam line PORV on the ruptured steam generator.with an operator-action delay time from_when it should have closed normally. The delay times > assumed are lLO minutes for control' room and 30 minutes for local operation.(credit).

Manually control-auxiliary feedwater to maintain zero power steam P nerator levels,(nominal).

Using the steam line PvRVs, initiate natural circulation cooldown of-the primary system after identif

th am assumed to occur.

Resamsc Iloth an increase in the main feedwater flow arxl a corresporxling decrease in temperature are assumed to occur. 'lhe magrdtude of the temperature decrease is conservatively calculated based on maintaining a constant heat addidon rate fmm the feedwater heaters.

I Question 2 Explain the reason why DPC's assumpdon regarding the PZR !cvel control shifted imm the g

automatic to the manual operadon for the turbine trip analysis ($3.1.l.4).

W Resnonse This revision corrects a typographical error in the original report. 'Ihe turbine trip analyses for txs the feedring and preheater steam generator designs were performed assuming that the pressarizer heaters are manually locked on. Tids augments the pressuriter pressure increase g

widch conserva'ively delays reactor trip on overtemperature AT.

3 Ouestion 3 Clanfy the SO level control description for the turbine inp.

Resnonse

'this question concems analysis methodology which has not been revised. In the turbine tdp analysis, main feedwater flow is conservatively isolated at the initiadon of the transient. If g

feedwater flow were to ccntinue, a portion of the primary system heat would be expended g

heating the subcooled feedwater up to saturation conditions as opposed to generating steam.

'Ihis would act to reduce the seccndary system pressure, which is non-conservative for all acceptance criteda.

Question 4 Explain the qualification on availability of the purge volume of hot MRV for the Loss of Non-Emergency AC Power Event (53.2.1).

Resnortse As it is used here, " purge volume" refers to the amount of relatively hot main feedwater that must be displaced from the auxiliary feedwater piping before the cold auxiliary feedwater can reach the steam generators. This purge volume is introduced because of the delivery of a small percentage of the main feedwater flow through the auxiliary feedwater piping and associated nozzles during steady-state full power operation. Plant operations staff at McGuire has eliminated this tempering flow practice, while Catawba has not. Therefore, the purge volume modeling is applicable only to Catawba analyses.

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Duestion 5 Explain why the high instead of low initial SO level is conservative for the ability to establish natural circuladon (93.2.4 loss of run-emergency AC power).

Ecsputnc As stated in the report, the high irdtlal level assumption tridmires the volume of the steam space in the steam generator. Following turbine trip, this smaller steam volume yields a greater pressuritation rate. The higher steam generator pressure (and saturadon temr ature) conservatively reduce the primary-to secondary heat transfer.

Iow steam generator level would be conservative only if the primary to-secondary heat transfer were degraded by tube bundle uncovery prior to the point at which the auxiliary feedwater heat removal capacity exceeds the core decay heat generation. Beyond this point, the transient tums around and primary system temperatures begin to decrease.

In the existing analysis, this transition point is reached approximatelv 10 minutes after the loss of offsite power. At that time, the steam generator 11guld inass has decreased by less than 15,000 lixn from its initial value of appmtimately 130,000 lbm. At this point in time, there is l

a large amomit of margin to tube bundle uncovery and heat transfcr degradation. This conclusion would remain valid even if de Inidal steam generator level was adjusted low rather l

than high.

Question 6 63.2 5.1 of Ref. 2 does not describe the turbine contrul. Please revise reference.

Renxmsc Automatic turbine control is modeled in P3TRAN as a negative fill junction with a constant flow rate, as described in 63.2.5.1 of DPC NE 3000. This simulates the modulation of the turbine control valves which act to maintain a constant turbine power and, therefore, a constant steam flow rate.

Ouestlon 7 Discuss and justify the timing of reactor trip in 53.3 (loss of normal feedwater), in addition, DPC should provide demonstration that both the RCS and SO pressure peaks are higher and the DNB is lower with earlier reactor trip with less mass in SO than with delayed trip. Discuss how the low low level trip setpoint is adjusted.

Remonse lhe loss of feedwater transient has been detennined to be bounded by the turbine trip event and is not routinely analyzed as part of the DPC licensing basis analyses. A reanalysis is perfonnea with the feed '.ng steam generators for the purpose of gencruting replacement FSAR figures.

Before a discussion of the trip setpoint adjustment can proceed, duce basic terms must be defined; nominal, indicated, and actual level. Nominal level is the proErammed value at which the plant la intended to operate. Indicated level refers to the control room indicadon, which may vary within a specified controller deadband around the nominal value. The actual level is

I the true water level in the steam generator, widch can differ fmm the indicated level by the measurernent uncertainty of the level instrument.

1he intent of die downward adjustment to the steam generator level was to promote the uncovc.ry of the tube tendle, as this would potentially degrade the primary to secondary heat transfer. If the initial level indication were adjusted upwafd, reactor trip on low low steam generator level would le delayed. Ilowever, this also intraluces competing effects. The delayed reactor trip would exterxl the RCS heatup but also die core power retluction due to moderator temperature feedback. Since this event is bounded by the turbine trip event, a demonstration of the limiting inidal steam generatorlevel condition is not necessary. Were this accident to become poterCally limiting in the future, a sensitivity study would te performed on the initial stearn gencrutor level assumption to ensure its conservatism.

In the analysis of the loss of feedwater transient, the actual level was initially set 8% below the nominal pmgrammed value. This allowance is a statistical combination of the contmiler deadband and irwtrument uncertainties. Although inherent in this assumpdon is the fact that the indicated level must te lower than nominal, it is conservatively assumed that the indication is at the nominal value fully 8% above the actual value. Physically, the reactor trips when the irxilcated value reaches the plant trip setpoint. In this RETRAN simulation however, the g

trip is modeled as if it occurred on actual level. Thetefore, the reactor trip occurs when the W

actual level reachs a value 8% below the low low steam generator level trip setpoint.

I Ouestion 8 Descrite in detail the long-term core cooling analysis of the Feedwater System Pipe Break g

event with revised transient assumptions and scenario. When and on which signal is the g'

turbine assumed to trip? Furthermore. discuss any impact from planned SG replacement on this transient analysis with respect to transient objectives, assumptions and scenario.

Resnonse lhe major impact of the feedring steam generators on this analysis is due to the design and g

location of the main feedwater nozzles. Since the main and auxiliary feedwater nozzles are g

now at approximately the same elevadon. It is conservatively assumed that the auxiliary feedwater enters and exits dv faulted steam generator without passing over the tube bundle and g

removing primary system ?

'is is a significant departure from the preheater steam g

generator response,wher

, diary feedwater delivered to the faulted generator must remove a significant amt heat prior to exiting through the break. Therefore,in the g

fecdring steam generato.

jsis it is conservadve to assume a late operator action time for g

the isolation of die faulted generator.

l In addition, since the main feedwater nozzle is consid.toly closer to the normal steam generator water level, following a short period of'.pid blowdown the broken feedwater line is relieving steam instead of water. This tends to ei. acerbate the overcooling phase of die feedline break transient, which continues until the faulted generator has blown dry.

A third notable impact of the feedring steam generators is due to the lack < a flow restricting l

orifice in the main feedwater nozzle. Because of this design difference, the faulted generator blows dry in roughly two-thirds of the time taken by the preheater steam generator.

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In lieu of performing a revised containment response calculation to determine the timing of the high high containment pressure signal actuadon, the following modifications were made to the transient analysis assumpdons. A loss of offsite power, which causes the reactor coolant pumps to coast down, is assumed to occur coincident with reactor trip on high contaltunent pressure safety injectior De pumps were previously assumed to be tripped manually on high-high contaltunent pressure. Also, steam line isoladon is assumed to occur coincident with turbine trip, which occurs on reactor trip with no response time delay. De superseded analysis methodology assumed that steam line isolation occurred automatically on high-high containment pressure, in both of the above cases the revised assumpdon is more conservadve than that which it replaces. Since, due to the feedring steam generator design, tle overteating transient is less lirnidng, these modifications do not intmduce any excessive conservatism.

Question 9

%c RCP locked Motor event is proposed to be analym Ing the SCD methodology, Discuss the applicability of the SCD methodology for this event analysis.

Resnonse

%e appmved DPC core thermal hydntulic statistical core design methodology, including the range of applicability,is described in DPC NE 2005P A. Although the core inlet flow for the locked mtor transient falls below the minimum SCD parameter value, a statistical Monte Carlo pmpagadon was performed to ensure that the statisdcal design limit (SDL) remained acceptable. De details of this statistical pmpagation methodology are discussed in 52.3 of the topical report. Using the BWCMV CilF correlation, the statistical analysis for die locked mtor transient yields a statepoint DNBR of 1.364, which confirms that die use of this conclation with an SDL of 1.40 is valid for this event.

Question 10 Discuss the impact of allowing a possibility of reactor trip on pressurizer high pressure for the analysis of the uncontmtled bank withdrawal from a subcritical or low power startup condition event.

Resnonse

%c subject revision simply includes a potentially applicable reactor trip function that was invivertently omitted fmm the original report. De actual analysis methodology for the uncontmiled bank withdraw al fmm a subcritical or low power startup condition event has not been modified.

Due to the rapid increase in neutron power once prompt criticality is achieved, a high pressure trip is much less likely than a high flux trip, liowever, if the analysis is performed with a lower reactivity insertion rate, it is possible that the core power increase might be slow enough to allow a high pressure reactor trip.

I Duestion 11 Since DPC is taking excepdon to the SRP guidelines with respect to the pressuriier overfill (for the inadvertent operation of ECCS during power operation transient) DPC should g

demonstrate that the analysis with the plant at teru powei does produce more conservadve g

PZR overilli analysis than does at the full power. Furthennore, discuss DPC's acceptance criterion fcr this event analysis.

Resnonse

%e Standard Review Plan stipulates that the Corxhdon II inadvertent operation of ECCS during power operation transient not give rise to a more serious Condition 111 event. A potential escalation scenario that wuld result in an unisolable small break LOCA involves the failure of the pressuriter safety valve to rescat following the relief of subcooled liquid.

I According to Westinghouse V!L W 93 18. In order to meet the applicable Condition 11 criterion, the PSV's must cliher not open or must be capable of closing after release of subcooled water, DPC mechanical maintenance support staff has affirmed that the PSV's will rescat if the liquid rellef temperature remains above 500*F. His low temperature limit is therefort chosen as the acceptance criterion for the event.

Zero power is chosen rather than full power as the initial condition for the analysis since Die RCS is at a lower average temperature and would therefore have a lower transient temperature response.

Question 12 l

Discuss any impact of feedring SO design on the SO Tube Rupture analysis. DPC needs to W

justify extending the SOTR methodology appioved for Catawba on McGuire appilcations.

Pmvide discussion of the expected primary loop subcooling during the entire time of analysis, g

Discuss the impact of modified PZR modeling on the PZR pressure, in the plant nodalization.

E discuss the impact of the PZR on the affected vs. unaffected loops. In addition, DPC should justify the applicability of the SCD methodology for this event analysis.

Resnonse There are three significant effects of the feedring steam generators on the SO1R analysis.

3 First, the feedring steam generator tubes are appmximately 10% smaller in diameter, which E

yields a pmportionally lower break flow rate. his introduces the competing effects of slower buildup of activity levels in the faulted steam generator and delayed recovery of the tube g

bundle. Secorxtly, the tube bundle in the feedring steam generator is approximately 8 feet 5

taller than the preheater steam generator, therefore there is the potential for a greater period of tube uncovery. hbc bundle uncovery has a direct be.uing on the entrainment of the break g

flow liquid droplets, which significantly impacts the activity of the steam released to the E

atmosphere. Birdly, the feedring steam generator liquid mass at full power is approximately 20,000 lbm greater than that in the preheater steam generator, his equates to a larger liquid g

volume available for mixing with the break flow and diluting the iodine concentration of the 5

steam relief.

Ec cunent approved methodology for McGuire is a non-mechanistic calculation which simply postulates 30 minutes of primary-to secondary break flow with no thermal-hydraulic transient simulation. Applying the methodology which has been approved for Catawba to the McGuire I

J

anrJysis is both a more physical and more conservative approach. Bure of the more significant areas of increased conservatism are: a) the pdmary-to-secondary break flow continues until the system pressures are equalized, b) the atmospheric release fmm the secondary system persists until the failed steam line PORV is isolated, and c) tube bundle uncovery is explicitly modeled (as discussed above). Finally, since the McGuire units will be virtually identical to Catawba Unit I followir.3 the steam generator replacement, the extension of the approved Catawba methodology is technically warranted.

Following the tube rupture, the RCS subcooling margin gradually decreases as RCS pressure decreases until reactor trip occurs. At this point, the RCS is still in a subcooled condition.

During the cooldown portion of the transient, the subcooling margin gradually increases since the rate at wHch the RCS temperature is decreasing more than compensates for the rate at which the F.CS is depressurizing. Aher the operators begin depressudzing the RCS to terminate break flow, the subcooling margin decreases, but always remains above 07.

Following identification of the ruptured SO, cooldown of the RCS is initiated using the operable SM PORVs on the intact sos. Uds cooldown continues until the RCS reaches a 207 subcooled condition relative to the ruptured SO pressure.10 minutes after this condition has been reached, operators begin depressudzing the RCS u ing a single pressudzer PORV until break flow is terminated.

Per 57.1.1, the local conditions heat transfer model was employed in the pressurizer in the original analysis methodology. Uds sentence is being removed from all of the event specific discussions since the modeling is now appiled generically as discussed in 13.2.3.3 of DPC-NE-3000, llowever, since this transient mainly consists of a prolonged pressurizer outsurge, the wall conductors do not play a significant role.

Since an outsurge of hot water from the pressurizer will occur as the RCS depressurizes during this event, the pressurizer is assumed to be attached to the lumped intact loops 'Ihis will maximize the break flow through the ruptured tube by minimizing the primary inlet temperature entering the ruptured steam generator.

Die tube rupture DNBR transient, which is analyzed completely independent from tie offsite dose analysis, is essentially a complete loss of reactor coolant flow event initiated from a reduced pressurizer pressure. At the minimum DNBR statepoint, all of the SCD treated parameters: core inlet temperature and flow, core exit pressure and core heat flux are within their respective parameter ranges for SCD applicability (Refer to Appendix B of DPC NE.

2005P-A).

Question 'J DPC should revise 59.0 (References) in Revision 1.

Respruc When Revision 3 to DPC-NE-3000 is approved, the references will be updated accordingly.

DukeIbuerCompany P0 Bat 1006 at 5 Tlan Owlotte NC582011006 Senior %cr hesident NuclearGeneration (704)382-2200OWsce (704)382-43G0 fax DUKEPOWER December 19,1995 U. S. Nuclear Regulatory Commission Washington, D. C. 20555 33 Attention Document Control Desk

Subject:

Duke Power Company hicGuire Nuclear Station Docket Numbers 50 369 and.370 Catawba Nuclear Station Docket Numbers 50-413 and -414 Minor Change to NRC Approved Methodology We purpose of this letter is to notify the NRC staff of a minor change to the NRC approved analysis methodology that Duke Power uses for FSAR Chapter 15 analyses to support the McGuire and Catawba Nuclear Stations. His methodology is detailed in the topical report DPC-NE-3002.A,"FSAR Chapter 15 System Transient Analysis Methodology." The specific modeling change is the assumed performance of the pressurizer code safety valves and the main steam code safety valves. In the licensed methodology it is stated that these valves "are modeled with lift, accumulation, and blowdown assumptions which manmize (or minimize) the pressurizer (or secondary) pressure." he specific minor change is in regard to the concept of accumulation during lift of a safety valve. Accumulatio i has been modeled as a linear opening of a safety valve beginning at the lift setpoint and reaching full open at a pressure corresponding to the lift setpoint plus an accumulation allowance which is typically 1 3% of the lift pressure setpoint. For example, a pressurizer safety valve with a lift setpoint of 2500 psig and 3% accumulation would reach full open at 2575 psig. Although this is a conservative modeling approach, it does not physically represent the real valve performance, which is best characterized a popping-open response. The proposed minor change to the approved modeling would be to model the valves as popping open with a conservatively slow response time. For each valve type for which this modeling is to be applied, valve testing data will be researched to determine the actual valve dynamic response.

%cse data will then be conservatively bounded by the new popping open modeling used in the RETRAN-02 model for McGuire and Catawba.

The need for this modeling change is twofold. Licensing basis analyses assuming +3% valve setpoint drift and the current 3% linear accumulation assumption can result in peak primary or secondary pressures which approach or exceed the overpressure limits. De proposed modeling significantly reduces the predicted peak pressures, thereby adding margin and avoiding other unnecessary and undesirabic attematives such as lowering the valve setpoints. He second cause is I

I

l U. S. Nuclear Regulatory Commission l

i December 19,1995 Page 2 l

t the design c,f the replacement steam generators which m,o be inst.lled at McGuire and Catawba I

Nuclear Stations, beginning in mid 1996. De increaae i. steam r merator heat transfer area in the

{

.W --- ^ steam generators results in higher peak sec adary p essures following turbine trip.

1

= De analysis results will exceed the secondary overpressu.. S.at unless this modeling change is

, implemented or the code safety valve seapoints are lowered, which would require a Technical t

4 1

Specification change. Lowering the valve setpoints is not desirable, and any unnecessary l

Technical Specification revisions should be avoided if possible.

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nis nxxicling change was discussed by phone with NRC staff'from the Mechanical Engineering

- and Reactor Systems Branches in May 1995. De conclusions from the discussions were that the

[

proposed modeling approach would be acceptable as long as the modeling was conservative -

t relative to the industry valve testing database. Dat constraint will be followed with the proposed 1

modeling approach, with a significant amount of conservatism maintained.

l i

NRC concurrence with this proposed modeling change will be necessary to avoid submittal of a topical report revision or a Technical Specification change. The application of this proposed modeling change is necessary to support the Catawba Unit I outage with steam generator i

4.

replacement, which is currently scheduled to start in April 1996.

?

[

If you would like to discuss this letter, please call Scott Gewehr at (704) 382 7581.

3 a

Very truly yours, i

Kkw i

1 M. S. Tuckman cc:

Mr. V. Norses, Project Manager 08 ice ofNuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail Stop 14H25,OWFN Washington, D, C, 20555.

Mr. R. E. Martin, Project Manager

- Office ofNuclear Rancsor Regulation U. S. Nuclear Regulatary Commission Mail Stop 14H25,OWFN t

- Washington, D. C. 20555

- Mr. S. D. Ebneter, Regional Admimstrator U.S, Nuclear Regulatory Commission - kespon U

. 101 Marusta Street,NW-Suite 2900 Atlanta, Georgia 30323_

~

- Mr. G. F. Maxwell

- Smior ResidentInspector

- McGuireNuclear Station J

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U. S. Nuclear R.gulatory Commission December 19,1995 Page 3 Mr. R. J. Freudenberger Senior Resident Insrector Catawba Nuclear Station Mr. C. G. Ilammer U. S. Nuclear Regulatory Commission Mail Stop 7E23, OWFN Washington, D. C. 20555 I

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U. S. Nuclear Regulatory Commission December 19,1995 Page 4 bxc:

G. A. Copp O. D. Swindlehurst ELL

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