ML20071N723

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

ML20071N723
Person / Time
Site:	Catawba
Issue date:	07/31/1982
From:	Forcht K, Lang G, Wiesemann R DUKE POWER CO.
To:
Shared Package
ML20071N713	List: ML20071N707 ML20071N723
References
NUDOCS 8306070210
Download: ML20071N723 (14)

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OVERPRESSURE PROTECTION REPOR'U n. .

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UNITS 1 & 2

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AS REQUIRED BY l

ASME BOILER AND PRESSURE VESSEL CODE SECTION III, ARTICI.E NB-7300 JULY 1982 I

l Prepared by: K. A. Forcht Approved: /

G< T.. Lang U Transient Analysis E

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i 1.0 Purpose of Report i 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 Protection 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 l which envelope those credible events which could lead to over-I pressure of the RCS if adequate ever pressure protection were not provided.

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1. Loss of Electrical Load and/cr Turbine Trip l

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 defined in 10CFR50 and includes:

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

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I 2. The reactor coolant side of the steam generators.

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3. Reactor coolant pumps.

i 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 i by load transients. A pressurizer 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.

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The spray nozzle is located in the top head of the pressur-izer. Spray is initiated when the pressure controlled spray demand signal is above a given setpoint. The spray race 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 contro ller, the input to which is an error signal based on the difference between actual pressure and a reference pressure.

The pressurizer is equipped with 3 power-operated relief valves which lhait 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

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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 lead decrease with steam dump but without reactor trip.

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.

r In the event of unavailability of the pressurizer spray or power operated relief valves, and a complete loss of steam flow to the turbine, protection of the RCS against overpres-sure is afforded by the pres,surizer safety valves in conjunc-tion with the steam generator safety valves and a reactor trip initiated by the Reactor Protection System.

There are 3 safety valves with a minimum required capacity of l 420,000 lb/ hour for each valve at system design pressure plus 1 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 NB7511. The i pressurizer safety valves and power operated relief valves I discharge to the pressurizer relief tank (PRT). Rupture disks are installed on the pressurizer relief tank to prevent PRT overpress urization.

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 en analy-l 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 1637Q

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lost, and e 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.

This sizing procedure results in a safety valve capacity well 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 procedure 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.

Review of these transients shows that the Turbine Trip results it. 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 po rible 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 race in the steam generator is reduced, causing the reactor coolant tem-perature to rise, which in turn causes coolant expansion,

' pressurizer insurge, and RCS pressure rise.

l 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 excess steam generation would be dumped to the atmosphere and main feedvater flow would be lost. For this situation feed-water flow would be maintained by the Auxiliary Feedwater System to ensure adequate residual and decay heat removal capability. Should the steam dump system fail to operate, the steam generator safety valves may lif t to provide pressure control.

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1637Q:1 (3)

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; that is, the turbine is assumed to trip without actuating all the sensors for reactor trip on the turbine stop valves. The assumption delays reacter 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 no credit taken for auxiliary feedwater to mitigate the consequences of the transient.

i The turbine trip transients are 2nalyzed by employing the detailed digital computer program LOFI'RAN. The program simu-lates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The program computes per-tinent plant 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 consistent with the steady state full power operation including allowances for calibration and instrument errors. The initial RCS pressure is assumed at a minbaum value consistent with the steady state full power operation including allowances for cali-bration and instrument errors. This results,in the maxi-mwm power difference for the load loss, and the minimun i margin to core protection limits at the initiation of the accident.

b. Moderator and Doppler coefficients of reactivity i

The analysis assumes both a least negative moderator coef-ficient and a least negative Doppler power coefficient, as this results 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 c ontro l. If the reactor were in automatic control, the control rod banks would move prior to trip and reduce the severity of the transient.

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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 saf ety valves Itaits secondary steam pressure *st the setpoint 'value.

e. Pressurizer spray and power operated relief valves No credit is taken for the effect of pressurizer spray and power operated relief valves in reducing or lisiting the coolant pre ssure . 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 I

condition will be reached before. auxiliary feedvater 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 maxiliary feedwater flow would remove core decay heat following plant stabilization.

( g. Reactor Trip l Reactor trip is actuated by the first Reactor Protectica System trip setpoint reached with no credit taken for 'che

, direct reactor trip on the turbine trip. Trip signals are ~

l expected due to high pressurizer pressure, Overtemperature AT, high pressurizer water level, and low-low steam generator water level.

The results of the Turbice Trip transient are shown in Figures 2 and 3. Figure 2 shows the pressurizer pressure, the reactor coolant pump discharge pressure, which is the point of highest

, pressure in the RCS, and the pressurizer safety valve relief rate. Figure 3 shows steam generator shell side pressure, l reactor coolant loop hot leg and cold leg temperature, and l

nuclear power. The reactor is tripped on a high pressurizer I

pressure signal for this transient.

The results 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 rata also ahows 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, Sectien III, Ar:icle l NB 7000, 1971 Edition Winter 1972 Addenda.

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,, ,s 3 .' Certified Safety Valve Cspacity, Calculation No. CPA 05; FA-790, July 2 3,198b.

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'4. DCP/DDP Loss of Load Analysis, Calculation No.

• CN-RPA-7 8-161, April, 1980. ,

i 1 Sr .)CP/DDP Rod Withdrawal of Power Analysis, Calculation No.

CN-RPA-7 8-160, Jene , 197 8.

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6. DCPs DDP f oss,/ of,' Flow / Locked Rotor Analysis, Calculation l < , No . ' CN-RFA-7 8-18 6, Decembe r, 197 8.

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- '. 7i DCP/DDP< Lo ss/of Norhal Feedwater/ Station Blackout Analysis J Calc 61ation No. CN-RPA-78-207, November,197.E.

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ECP/DDP~ Lesi of Load Analysis with 0FA, Calculation No.

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- Ci-RPA49-57, July , 19 7 9.

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, 9. DCP/DDPhod Withdrawal of Power Analysis with 0FA, Calculat!'on No. CN-RPA-79-5 6, March,1982.

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10. DCP/DDP [o ss of Flow / Locked Rotor Analysis with 0FA,

Calc 61af, ton No. CN-RPA-79 -91, May ,1980.

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11. DCP/JDP Loss of Yo rmal Feedwa'ter/ Station Blackout wita OFki . Calculatior No. CN RPAl /9-5 5, June ,1980.

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. 0VERPRESSURE PROTECTION REPORTS Ref: NS-PL-7932 to D.M.' Popp -

412 cc: S.N. Ehrenpreis 411 N.P. Mueller .

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R.S. Howard 526 File: DCP-300 Per the reference request, we have reviewed the required pressurizer safety valve capacity for the DCP/DDP plant. It is hereby certified that the re-quired safety valve capacity meets the requirements of ASME Boiler & Pres-sure Vessel Code,Section III NB-7300, 1971 Edition through Winter 1971 addenda (DCP) and through Winter 1972 addenda IDDP).

The' plant parameters were reviewed by the undersigned to determine that the Catawba Units are directly equivalent to the McGuire Units,. Therefore, Cat-culation Note CPA-72-5 which documents the method by which the required l capacity for the safety valves for the McGuire Units is determined applies to the Catawba Units. .

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(440.129) vessel the downcomer would be relatively smaller than for most UHI plants. Justify that Catawba is not " imperfect mixing" limited as is the other "small downcomer" UHI plant.

Response

Three additional DECLG break cases have been analyzed n(C = 0.8, 0.6 and 0.4) assuming that imperfect mixing of UHI water occDrs in the reactor vessel upper head; the results obtained are summarized in Table Q440.147-1 and -2. The previously identified limiting break (C = 1.0 DECLG, perfect mixing) for Catawba, which produced a caiculatedpeakcladtemperatureof2155*F,remainsthelimitingcase.

440.148 Question deleted - Issue Resolved in FSAR, Revision 6.

440.149 Table 440.3-3 and the response to Q440.56 indicate that credit has (15.6.3) been taken for non-safety grade equipment, without applying single (440.127) failure, and without loss of offsite .wwer in the analysis of steam generator tube rupture. Provide an analysis fo this event with loss of offsite power, applying single failure, and taking credit only for safety grade systems and instrumentation in the mitigation of the event.

Response

The analysis of the steam generator tube rupture event assumed the loss of offsite power coincident with reactor trip. Maximization of steam released through the faulted steam generator safety valves and power operated relief valve was obtained by assuming the limiting single failure within the auxiliary feedwater system that then results in minimum delivered auxiliary feedwater flow. As discussed in Sec-tion 15.6.3.2, no operator actions are assumed until 30 minutes after the accident. During this time period no credit is taken for non-l 1

qualified (i.e., non-safety grade) equipment.

The Chapter 15 analysis assumes that the operator takes action at 30 minutes to depressurize the primary system and, thereby, termi-nate the steam release to the atmosphere through the faulted steam generator safety valves. Depressurization will be accomplished via any of several methods depending upon the availability of the com-ponents and power supplies. Depressurization following a SGTR will be accomplished in three stages. The first stage involves depres-surizing the reactor coolant system to a pressure slightly less than l

that of the faulted steam generator secondary side. The second and third stages bring RCS pressure down to RHRS initiation conditions (approximately 415 psia) and, finally, to atmospheric pressure, i Adequate time exists for both the second and third depressurization l stages to permit manual actions to recover previously unavailable

! components.

440-135 Rev. 8 l

TABLE Q440.147-1 LARGE BREAK TIME SEQUENCE OF EVENTS, IMFERFECT MIXING DECL C = DECL C DECL C (SSc)0.8 (SSc=)0.6 (SSc=)0.4 START 0.0 0.0 0.0 Rx Trip Signal .778 .795 .823 S. I. Signal 4.9 5.0 5.3 Acc. Injection (CL) 15.1 17.7 23.3 End of Blowdown 63.4 67.2 74.3 Bottom of Core Recovery 67.5 63.9 76.4 Acc. Empty (CL) 115.0 118.8 126.6 Pump Injection 29.9 30.0 30.3 End of Bypass 45.8 47.5 55.7 l

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440-135a Rev. 8 New Page 1

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TABLE Q440.147-2 LARGE BREAK - IMPERFECT MIXING DECLG CASES Results C = 0.6 CD = 0.8 D CD = 0.4 Peak Clad Temp. *F 2110 2144 2006 Peak Clad Location Ft. 7. 5 7.5 7.5 Local Zr/H 2O Reaction (max) % 5.9 6.5 4.1 Local Zr/H2O Location Ft. 7.5 7.5 7. 5 Total Zr/H O 2 Reaction % <0.3 <0.3 <0.3 Hot Rod Burst Time sec 64.0 64.0 77.0 Hot Rod Burst Location Ft. 5.75 6.5 5.5 Calculation Assumptions Core Power (Rod Heatup Calculation), MWt, 102% of 3411 Peak Linear Power kw/ft 102% of 12.63 Peaking Factor (At License Rating) 2.32 Accumulator Water Volume (Cold Leg, Nominal Setpoint Value) 1050 ft3 per accumulator Accumulator Water Volume Delivered (UHI, Nominal Delivered Value) 877 fts UHI Tank Gas Pressure 1300 psia l

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l 440-135b Rev. 8 l New Page

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