ML20010F607

Overpressure Protection Rept for Bryon/Braidwood Nuclear Power Plant Units 1 & 2 as Required by ASME Boiler & Pressure Vessel Code,Section Iii,Article NB-7300.

ML20010F607
Person / Time
Site:	Byron, Braidwood
Issue date:	06/30/1981
From:	Beyard D, Brown R AFFILIATION NOT ASSIGNED
To:
Shared Package
ML20010F601	List: ML20010F600 ML20010F607
References
NUDOCS 8109100419
Download: ML20010F607 (10)

Text

{{#Wiki_filter:_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ OVERPRESSURE PROTECTION REPORT FOR BYRON /BRAIDWOOD NUCLEAR POWER PLANT UNITS 1 & 2 AS REQUIRED BY ASME BOILER AND PRESSURE VESSEL CODE SECTION III, ARTICLE NB-7300 JUNE 1981 Prepared by: R. J. Brown Contributions by: L. K. Casagrande J. S. Fuoto Approved: %_ n_, D. G. B@ar\d . Licence Appliration Analysis

                                                                                                                          >$i3yV2%c Certified:                      y/       [[,L/4/4/L444J                     /r               %

Robert A. Wiesemam. fyy,yl, Pr.cri ::i v' - Prof es sional Engineer-0087 ~ ~ai n. o 772Ef';;M

                                                                                                                                                     ,;7      ,,

Commonwealth of Pennsylvan 'i_ ~ ' c:str.c . , i r:o. :m i -

                                                                                                                                          .r-l 8109100419 810903

• PDR ADOCK 05000454 PDR A

1.0 Purpose of Report This report documents the overpressure protection provided for the Reactor Coolant System (RCS) in accordance with the ASME Boiler and Pressure Vessel Code, Section III, NB-7300. 2.0 Description of Overpressure ?rotection 2.1 ' Overpressure protection is provided for the RCS and its compo-nents to prevent a rise in pressure of more than 10% above the system design pressure of 2485 psig, in accordance with NB-

                   .7400. This protection is afforded for the following events which envelope those credible events which could lead to over-pressure of the RCS if adequate over pressure protection were not prcvided.

1. Loss of Electrical Load and/or Turbine Trip

2. Uncontrolled Rod Withdrawal at Power

3. Loss of Reactor Coolant Flow

4. Loss of Normal Feedwater

5. Loss of Offsite Power to the Station Auxiliaries 2.2 The extent of the RCS is as defin< d in 10CFR50 and includes:

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

2. The reactor coolant side of the steam generators.

3. Reactor coolant pumps.

4. A pressurizer attached to one of the reactor coolant loops.

5. Safety and relief valves.

6. The interconnecting piping, valves and fittings between the principal components listed above.

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

2.3 The pressurizer provides volume surge capacity and is designed to mitigate pressure increases (as well as decreases) caused by load transients. A pressu izer spray system condenses steam at a rate sufficient to prevent the pressurizer pressure from reaching the setpoint of the power-operated relief valves during a step reduction in power level equivalent to ten per-cent of full rated load. N

The spray nozzle is located in the top head of the pressur-izer. Spray is initiated when the pressur< controlled spray demand signal is above a given setpoint. The spray rate increases proportionally with increasing compensated error signal until it reaches a maximum value. The compensated error signal is the output of a proportional plus integral controller, the input to which is an error signal based on the 4 difference between actual pressure and a reference pressure. The pressurizer is equipped with 2 power-operated relief valves which limit system pressure for a large power mismatch to avoid actuation of the fixed high pressure reactor trip. The relief valves are operated automatically or by remote manual control. The operation of these valves also limits the frequency of opening of the spring-loaded safety. valves. Remotely operated stop valves are provided to isolate the power-operated relief valves if excessive leakage occurs. The relief valves are designed to limit the pressurizer pressure to a value below the high pressure trip setpoint for all design transients up to and including the design percentage step load decrease with steam dump but without reactor trip. 4 Isolated output signals from the pressurizer pressure protec-tion channels are used for pressure control. These are used

to control pressurizer spray and power-operated relief valves in the event of increase in RCS pressure.

In the event of unavailability of the pressurizer spray or power operated relief valves, and a complete loss of steam j flow to the turbine, protection of the RCS against overpres- ! sure is afforded by the pressurizer safety valves in conjunc-tion with the steam generator safety valven and a reactor trip initiated by the Reactor Protection System. l There are 3 safety valves with a minimum required capacity of 420,000 lb/ hour for each valve at system design pressure plus ~ 3% allowance for accumulation. The pressurizer safety valves are totally enclosed pop-type, spring loaded, self-activated valves with back pressure compensation. The set pressure of the safety valves will be no greater than system design pres-sure of 2485 psig in accordance with section NE7511. The pressurizer safety valves and power operated 2:elief valves discharge to the pressurizer relief tank (PRT). Rupture disks are installed on the pressurizer relief tank to prevent PRT ! overpressurization. l Figure 1 shows a schematic arrangement of the pressure reliev-ing devices. 3.0 Sizing of Pressurizer Safety Valves 3.1 The sizing of the pressurizer safety valves is based on analy-sis of a complete loss of steam flow to the turbine with the reactor operating at 102% of Engineered Safeguards Design

Power. In this analysis, feedwater flow is also assumed to be e

w lost, and no credit is taken for operation of pressurizer power operated relief valves, pressurizer level control sys-tem, pressurizer spray system, rod control system, steamdump system or steam line power operated relief valves. The reac-tor is maintained at full power (no credit for reactor trip), and steam relief through the steam generator safety valves is considered. The total pressurizer safety valve capacity is required to be at least as large as the maximum surge rate into the pressurizer during this transient. l l This sizing procedure results in a safety valve capacity well l in excess of the capacity required to prevent exceeding 110% of system design pressure for the events listed in Section 2.1. The conservative nature of this sizing procedura is demonstrated in the following section. 3.2 Each of the overpressure transients listed in Section 2.1 has been analyzed and reported in the Final Safety Analysis Report. The analysis methods, computer codes, plant initial conditions and relevant assumptions are discussed in the FSAR' for each transient. Beview of these transients shows that the Turbine Trip resulta in the maximum system pressure and the maximum safety valve relief requirements. This transient is presented in detail below. For a turbine trip event, the reactor would be tripped directly (unless below approximately 10 percent power) from a signal derived from the turbine stop emergency trip fluid pressure and turbine stop valves. The turbine stop valves close rapidly (typically 0.1 seconds) on loss of trip fluid pressure actuated by one of a number of possible turbine trip signals. This will cause a sudden reduction in steam flow, resulting in an increase in pressure and temperature in the steam generator shell. As a result, heat transfer rate in the ! steam generator is reduced, causing the reactor coolant tem-

perature tr rise, which in turn causes coolant expansion, pressurizer insurge, and RCS pressure rise.

The automatic steam dump system would normally accommodate the excess steam generation. Reactor coolant temperature and pressure do not significantly increase if the steam dump sys-tem and pressurizer pressure control system are functioning , properly. If the turbine condenser were not available, the l excess steam generation would be dumped to the atmosphere and main feedwater flow would be last. For this situation feed-water flow would be maintained by the Auxiliary Feedwater l System to ensure adequate residual and decay heat removal capability. Should the steam dump system fail to operate, the l steam generator safety valves may lift to provide pressure ! control. l i l l N w

In this analysis, the behavior of the unit is evaluated for a complete loss of steam load from 102 percent of full power without direct reactor trip; tnet is, the tur ine b is assumed to trip without actuating all the tensors for reactor trip on the turbine stop valves. The assumption delays reactor trip until conditions in the RCS result in a trip due to other signals. Thus, the analysis assumes a worst transient. In addition, no credit is taken for steam dump. Main feedwater flow is terminated at the time of turbine trip, with r.a credit taken for auxiliary feedwater to mitigate the consequences of the transient. The turbine trip transients are analyzed by employing the detailed digital computer program LOFTRAN. The program simu-lates the neutron kinetics, RCS, pressurizer, pressurir.er relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The program computes per-tinent plaat variables including temperatures, pressures, and power level. Major assumptions are summarized below:

a. Initial operating conditions The initial reactor power and RCS temperatures are assumed at their maximum values consis tent with the steady s tate full power operation including allowances for calibration and instrument errors. The initial RCS presaure is assumed at a minimum value consistent with the steady state full power operation including allowances for cali-bration and instrument errors. This results in the maxi-mum power differe ce for the load loss, and the minimum margin to core protection limits at the initiation of the accident.

b. Moderator and Doppler coefficients of reactivity The analysis assumes both a least negative moderator coef-ficient snd a least negative Doppler power coefficient, as this resutts in maximum pressure relieving requirements.

c. Reactor control From the standpoint of the maximum pressures attained it is conservative to assume that the reactor is in manual control. If the reactor were in automatic control, the control rod banks would move prior to trip and reduce the severity of the transient.

N

d. Steam release No credit is taken for the operation of the steam dump system or steam generator power operated relief valves.

The steam generator pressure rises to the safety valve setpoint where steam release through safety valves limits secondary steam pressure at the setpoint value.

e. Pressurizer spray c2o power operated relief valves No credit is taken for the effect of pressurizer spray and power operated relief valves in reducing or limiting the coolant pressure. Safety valves are operable.

f. Feedwater flow Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No credit is taken for auxiliary feedwater flow since a stabilized plant condition will be reached before auxiliary feedwater initiation is normally assumed to occur; however, the auxiliary feedwater pumps would be expected to start on a trip of the main feedwater pumps. The auxiliary feedwater flow would remove core decay heat following plant stabilization.

g. Reactor trip is actuated by the first Reactor Protection System trip setpoint reached with no credit taken for the direct reactor trip on the turbine trip. Trip signals are expected due to high pressurizer pressure, Overtemperature AT, high pressurizer water level, and low-low steam generator water level.

The results of the Turbine Trip transient are shown in Figures 2 and 3. Figure 2 shows the pressurizer pressure, the reactor coolant pump discharge pressura, which is the point of highest pressure in the RCS, and the r -isurizer safety valse relief rate. Figure 3 shows steam generator shell side pressure, reactor coolant loop hot leg and cold leg temperature, and nuclear power. The reactor is tripped on a high pressurizer pressure signal for this transient. , The rr ults of this analysis show that the overpressure pro-tection provided is sufficient to maintain peak RCS pressure below the code limit of 110% of system design pressure. The plot of pressurizer safety valve relief rate also shows that adequate overpressure protection for this limiting event could be provided by two of the three installed safety valves. 4.0 References

1. ASME Boiler and Pressure Vessel Code, Section III. Article NB 7000, 1971 Edition Winter 1972 Addenda.

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

2. Topical Report - Overpressure Protection for Westinghouse Pressurizer Water Reactors, WCAP 7769, Rev. 1, June 1972.

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

4. CAF. OFA Loss of Load Accident (FSAR Amendment), Calcula-tion No. CN-PP-80-94, September, 1979.

5. CAE FSAR Loss of Load / Turbine Trip Calculatic7 No. CN-RPA-78-65, April, 1978.

6. CAE Underfrequency/ Loss of Flow / Locked Rotor Analysis for OFA-STAT ONB & Broken Pump Shaft, Calculation No. CN-PP-80-129, November, 1980.

7. CAE FSAR Loss of Flow & Locked Rotor; Broken Pump Shaf t; Underfrequency Analysis Calculation No. CN-RPA-78-49,

March , 1978.

8. CAE OFA Amendment - Loss of Normal Feedwater and Station Blackout, Calculation No. CN-PP-80-115, November, 1980.

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

10. CAE OFA FSAR Amendment - Rod Withdrawal at Power Analysis, CN-PP-80-107, October, 1980.

11. CAE Rod Withdrawal at Power Calculation No. CU-RPA-78-36, Feb ruary, 1978.

12. CAE OFA Turbine Trip for Overpressure Protection Report, Calculation No. CN-PP-81-2, January, 1981.

t e

C  : TO PRESSURIZER

                                                                   !              //                            ______.         _ _ __.R{ LIE F VALVE l                               d._.1 OUTSIDE        INSIOE                                            '/       ,                          -                      1
                                                                   ,                      g
                                                                                                             ?

CONTAINMENT CONTAINMENT i g) I]g f.Q g og-#C ^

                                                                                                                               -RELIEF le VALVES :

MAIN STE AM A VE " ~ *

• SAFE TY VALVES 8 pg y __ g_ _g _ _ y_ , j

                                                                  ' 'p                       %                            $     PT    PC --

f STE AM -

                                                              ,,                                   LT                      ty GENERATOR 1                     FROM PR E SSUR E TO IURBINE                                                     CONTROLL E R

__ _ q SifAM PRESSURIZE R GENERA 1OR 2 SPRAY LINE LOOP 1 ' LOOP 2 i REACTOR REACIOR l COOLANT COOLANT PUMP 1 PUMP 2 g REACTOR VESSEL STEAM

• STE AM CENER ATOR 4 GENERATOR 3 I LOOP 4 LOOP 3 - PIPING REACTOR REACTOR ---

INSTRUMENTATION LINE COOLANT COOLANT PT PRESSUaE TRANSMITTER , PUMP 4 PUMP 3 PC PRESSURE CONTROLLER i' i LT LEVEL TRANSMITTER -

                                               .                                                                                                              {p . .          c ir, u

8 Figure 1. Schematic Arrangement Of Pressure flelieving Devices l, 2.1 -

e 4 4 19305

      $ 2600 m

E 2s00 w

      $ 2400       -

h e 2300 g 2200 m 5 2100 - e 3 2000 e p 1900 - 4 1800 2700 5 2600 - E

     ; 2s00       -

e D 2400 - E y 2300 nm - 5 . 3 2100 - 0 2000 - D E 1900 - 1800 1.0

   $_      0.8   -

m-d'N 0.6 -

   =c WU
   >w
   $0      0.4   -
   >e4
   >G w5      0.2   -

a O { l l I I O 10 20 30 @ M TIME (SEC) Figure 2.

                                         ~

O 6

      @*                                                                 g s

e I I i i 1 5 1250 - if 1200 e h1150 m [ 1100 . b 1050 a 2

               < 1000 w

G 950 - 900 650 640 o', 620 k 600 - 8 sao - N 560 - 550 _ 1.2 2 o z 1.0 u. O d

                 < 0.8 E

w g 0.6 m 20.4 - x 0.2 00 0 10 20 30 40 50 60 TIME (SEC) Figure 3}}