INVESTIGATION OF CRITICAL SAFETY FUNCTION INTEGRITY IN CASE OF STEAM LINE BREAK ACCIDENT FOR VVER 1000/V320

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1 International Conference 12th Symposium of AER, Sunny Beach, pp , September, INVESTIGATION OF CRITICAL SAFETY FUNCTION INTEGRITY IN CASE OF STEAM LINE BREAK ACCIDENT FOR VVER 1000/V320 Antoaneta E. STEFANOVA, Rositsa V. GENCHEVA, Pavlin P. GROUDEV Institute for Nuclear Research and Nuclear Energy, Tzarigradsko Shaussee 72, Sofia 1784, Bulgaria ABSTRACT In this paper are presented the results of investigation of critical safety function (CSF) Integrity in case of Steam Line Break (SLB) accident. The investigation has been done in supporting of Symptom Based Emergency Operating Procedures for VVER1000/V320. This kind of analyses are designed to provide the response of monitored plant parameters to identify symptoms available to the operators, timing of the loss of critical safety functions and timing of operator actions to avoid the loss of critical safety functions or core damage. RELAP5/MOD3.2 computer code has been used to simulate the SLB accident in a VVER1000 NPP model. This model was developed and validated at the Institute for Nuclear Research and Nuclear Energy for analyses of operational occurrences, abnormal events, and design bases scenarios. The model provides a significant analytical capability for the specialists working in the field of NPP safety. I. INTRODUCTION The maximum challenged Critical Safety Function in case of Steam Line Break is primary side Integrity. Steam Line Break event is characterized by rapid decreasing of pressure in the failed Steam Generator and in the Main Steam Header. Other symptoms include decreasing of water level in the failed SG #1 and decreasing of primary system temperature and pressure. After a while primary pressure will reach the set point for safety injection system actuation (one Makeup pump). As a result of this primary side pressure stabilizes, while the coolant temperature decreases rapidly. It creates conditions for reactor over pressurization and respectively challenges the CSF Integrity.

2 The represented NPP in this investigation is a VVER1000 pressurized water reactor that produces 3000 MW thermal power and generates 1000 MW electric power. The VVER1000 design includes four coolant loops, each one including one main coolant pump and one horizontal steam generator. This analysis is used for validation and verification of Symptom Based Emergency Operating Procedures for VVER 1000 units at Kozloduy NPP. II. EVENT DESCRIPTION The initiating event of this investigation is a total steam line break - ID 580 mm - on the steam line of the SG#1 upstream of BZOK. For Large Secondary Break an immediate pressure decreasing in the failed SG occurs, which results in reactor SCRAM and consequent Turbine Stop Valve closing. Steam generator water level in the failed SG decreases rapidly. An extensive primary system cooldown appears. Primary water volume shrinks initially. It results in PRZ water level and primary pressure decreasing. Primary pressure and PRZ water level are restored by Makeup system actuation. In this situation the most challenged is CSF Integrity. For investigation of the CSF Integrity, by engineering judgment, it was taken a decision to run the calculation at hot reactor shutdown conditions, which means at nominal reactor pressure and temperature but no decay heat is assumed. It is also accepted minimum water level in all SGs, which means minimum accumulated heat in the secondary side. This paper presents the results of two calculations: Base Case Calculation and Operator Action Calculation in case of postulated equipment failures. III. BASE CASE OF SLB INTEGRITY As a boundary condition for investigation of CSF Integrity it is assumed that SGs water levels are minimal 1.71 m because we would like to have minimum accumulated heat in secondary side. In this way, reestablishing of SG water level with colder feed water will maximum increases the steam generator heat sink capability. Scenario I.Initial status I.1. Hot reactor shutdown conditions reactor system is at normal operating pressure and temperature but no decay heat is assumed. I.2. Actuation of only one Makeup pump. I.3. Reactor Systems respond without operator actions. I.4. It is assumed that the SGs water levels are 1.71 m. II.Schedule of automatic and operator actions II.1. In accordance with signals P SG < 50 kgf/cm 2 and t S(I-II) > 75 0 C pumps TQ11DO1, TQ12DO1, TQ13DO1 are actuated.

3 II.2. In accordance to the signals P SG < 45 kgf/cm 2 and t S(I-II) > 75 0 C the MCP of damaged SG switch off. II.3. In accordance to the signals Pressure of Check Valve (CHV) - P CHV on steam line P CHV < -2 kgf/cm 2 and P SG < 50 kgf/cm 2 and with accordance with both set points it switchs off MCP of corresponding SG and it isolates the damaged SG from Feed Water Line (FWL) with delay of 30 sec. II.4. After reaching P SG < 50 kgf/cm 2 and t S(I-II) > 75 0 C BZOK closes with 10 s delay and in this way the damage SG is isolated from the Main Steam Header (MSH). II.5. By reaching P containment > 0.3 kgf/cm 2 in containment it starts an injection of sprinkler system by pump TQ11DO1. II.6. By reaching P SG < 50 kgf/cm 2 and P CHV < -2 kgf/cm 2 it actuates a signal for stopping of injection of Emergency Feed Water. Results The calculated sequence of events for the Base Case for SLB - Integrity is presented below. Table 1 Event Time, s Steam Line Break, ID MCP #1 is tripped 4.0 BZOK at faulted SG #1 closes 10.5 Isolation of feed water to SG # Minimum Pressurizer Water Level 3.77 m Stabilization of primary circuit pressure at 15.9 MPa Opening of Spray valve and injection to Pressurizer from cold leg #1 Dryout of SG #1 (SG water level 3 cm.) The most important parameter behavior is shown from Figure 1 through 6. The calculation was performed up to 2000 s into the transient time.

4 Reactor system is a subcritical at hot conditions. No fission product decay option as a bounding condition was used for receiving maximum cooldown rate for primary side. Core exit temperature for hot conditions was accepted 558 K. Should a steam line break appear, MCP #1 is tripped due to the signals P SG < 45 kgf/cm 2 and t S(I-II) > 75 0 C. All BRU-Ks open (due to closing of turbine stop valves in hot conditions). After 24.0 sec transient time BRU-Ks close by low-pressure signal. The important system parameter trends for this break are an uncontrolled pressure decreasing in faulted SG and this SG is completely depressurized. The behavior of faulted SG pressure is presented in Figure 1. The other symptoms include decreasing steam generator water level of faulted SG (presented in Fig. 5.) and initially decreasing primary pressure (presented in Figure 1.) and temperature (presented in Figure 4.). A rapid, extensive primary system cooldown occurs. Primary to secondary heat transfer is presented in Figure 3. As the primary system temperature drops, the heat transfer to the steam generator (faulted SG) and the primary system cooldown rate will be reduced. This trend will continue to the point where the primary system water volume shrinkage (cause by the cooldown) is overcome by the Make up system flow rate. Approximately, after 170 sec. the primary pressure drops to 12.6 MPa (due to shrinkage of primary side coolant) and begins to increase due to work of Make up system (there was no decay heat in primary side). Primary side pressure did not reach a set point of starting TQ13DO1 HPP. Heat transfer in faulted SG drops rapidly to 36 MW after dryout of SG#1 below 40 cm at 260 sec. Maximum heat transfer 730 MW from primary to secondary side in faulted SG was reached at 10 sec. (see Figure 3.). Behavior of cold leg liquid temperature is presented on Figure 4. The plate in core exit temperature comes at 30 sec due to isolation of feed water.

5 The steam generator blowdown is almost completed in 400 sec and further cooldown of the primary system is controlled mainly by the auxiliary feedwater flow to the other SGs. After 1500 sec transient time cooldown of the primary system is totally controlled by the auxiliary feedwater flow to the other SGs. Comparison of pressure in primary and secondary side is shown in Figure 1. During the whole transient time there is a reverse flow rate through faulted SG caused by work of other three MCPs. The break flow rate is presented on Figure 2. Figure 6. presents the behavior of Pressurizer water level. The Pressurizer water level was assumed to be 7.6 m in hot conditions instead of 8.7 m as in nominal. Also, Make up system works with maximum flow rate of 80 m 3 /hr from the beginning of transient in support of low level in pressurizer. The let down flow rate was assumed to be constant - 25 m 3 /hr to the end of calculations. For the first 180 sec the fast decreasing of Pressurizer water level comes due to cooldown of primary side and it caused primary system water volume shrinkage, when the pressure drops rapidly. The reason of increasing the Pressurizer water level after the first 180 sec comes from Make-up system work. The Pressurizer spray valve opens and starts to cycle and to inject cold water from leg #1, using the MCPs of the other loops. IV. PERFORMANCE OF OPERATOR ACTION CALCULATION INTEGRITY Following the methodology in the operator action calculation it is accepted failure of stop of feedwater and the operator actions at the selected time to verify that this action has restored the critical safety function Integrity. In The operator action there are two possibilities to reduce velocity of cooldown rate for the reactor system. The first one is to stop feed water to damaged SG and in this way we go back to base case. The second one is to stop other three MCPs and this way to reduce flow rate through faulted SG. This variant is investigated here. Scenario: Initial status the same as in Base case calculation. In the scenario for Operator system calculation it was assumed as an operator action switching off MCPs #2, 3 and 4 in the third minute from the begging of transient. The calculated sequence of events for the Operator Actions for SLB is presented below. Table 2 Event Time, s Steam Line Break, ID MCP #1 is tripped 4.0

6 BZOK at faulted SG #1 closes 10.5 Minimum water level in SG # m 34.8 Operator stops MCPs #2, 3 and Minimum Pressurizer Water Level 1.76m The most important parameters behavior is shown from Figure 7. through 12. The calculation was performed up to 2000s into the transient time. Figure 7. presents the primary side pressure behavior. The pressure in Primary circuit did not reach the set point of starting injection of HPP. Reactor system is a subcritical at hot conditions. No fission product decay option as a bounding condition was used for receiving maximum cooldown rate for primary side.

7 Should a steam line break appear, MCP #1 is tripped due to the signals P SG < 45 kgf/cm 2 and t S(I-II) > 75 0 C. The BRU-Ks open (due to closing of turbine stop valves in hot conditions). After 24.0 sec transient time BRU-Ks close by low-pressure signal. The important system parameter trends for this break are an uncontrolled pressure decrease in faulted SG. The behavior of faulted SG pressure is presented in Figure 7 The intact SGs are depressurized. This comes due to cooldown these SGs by primary side. The other symptoms include decreasing of steam generator water level of faulted SG, but after reaching 1.34 m at 34.8 sec, SG water level in SG #1 back again due to work of feed water. Decreasing of primary side pressure is presented in Figure 7. In the case with operator action there is almost the same deep depressurization of primary side, but switching off MCPs by operator delayed cooldown and that way and shrinkage of coolant is less. The earlier stopping of primary depressurization comes due to switching off MCPs. Approximately, after 520 sec. the primary pressure drops to 11.5 MPa (due to shrinkage of primary side) and begins to increase due to work of Make up system (there was no decay heat in primary side). The behavior of cold leg liquid temperature is presented in Figure 10. A rapid and extensive primary system cooldown occurs, too. Primary to secondary heat transfer is presented on Figure 9. Heat transfer in faulted SG drops rapidly after decreasing primary side liquid temperature. Maximum heat transfer of 730 MW from primary to secondary side in faulted SG was reached at 10sec. (see Figure 9.). As in failed calculation, the damaged SG #1, continue to cooldown primary side to the end of calculation. After some time (approximately 74 sec) primary side system starts to cooldown other SGs and it caused their depressurizations. Behavior of cold leg liquid temperature is presented on Figure 10. The break flow rate is presented on Figure 8. The steam generator blowdown continue to the end of calculation. The value of blowdown flow rate after depressurization of SG #1, depends of feedwater controller. In this calculation was assumed that feedwater controller will support the nominal SG water level of 2.4 m. During the whole transient time there is a reverse flow rate through faulted SG caused by work of the other three MCPs. After switching off MCPs #2, 3 and 4, reverse flow rate through SG #1 decrease significantly. The pressurizer water level depends from work of Make up system and shrinkage of coolant in RCS. Switching off the MCPs by operator delay shrinkage, how it was mention above and in this way pressurizer water level decreasing is reduced The minimum pressurizer water level was reached at sec 1.76 m. After this moment injection of water by Make up system dominate shrinkage of coolant and starts increasing of pressurizer water level. V. CONCLUSIONS: The Base Case calculation shows that with minimum resources and without operator actions the cooldown rate is in acceptable margin. The reactor system does not over pressurized by make up system and reactor system parameters are not in the dangerous area corresponding to cold over pressurization.

8 The main conclusion for Base Case calculation is that the safety systems are effective for an automatic plant recovery. The main conclusion for Operator Action calculation is that the action is not enough effective for a plant recovery. There is only one way to stop further cooling down of RCS to isolated faulted SG from Feedwater. VI. REFERENCES: [1] Carlson, K.E. et. al., RELAP5/MOD3.2 Code Manual Vol. 1,2,3 and 4 Draft, NUREG/CR-5535 (1990). [2] International Atomic Energy Agency, Guidance for Accident Analysis for VVER Nuclear Power Plants, VVER-SC-094, Vienna (1995). [3] Overall Plant Design Descriptions VVER Water Cooled, Water-Moderated Energy Reactor, DOE/NE-0084, Revision 1, (1987). [4] Ustanovka Reactornaia V-320. Poiasnitelnaia Zapiska. Opisanie Proektnyh Rejimov P31, GKAE. OKB, Gidropress (1971) (in Russian). [5] Groudev, P.P., et. al., Steam Generator PGV 1000 Processes Modeling Using RELAP5/MOD2, Mathematical Models in Nuclear Safety and Radiation Protection, Sofia, April [6] Data Base for VVER 1000, Safety Analyses Capability Improvement of KNPP (SACI of KNPP) in the field of Thermal-Hydraulic Analysis, BOA A-R4, INRNE-BAS, Sofia. [7] Engineering Hand Book, Safety Analysis Capability Improvement of KNPP (SACI of KNPP) in the field of Thermal-Hydraulic Analysis, BOA A-R4, INRNE-BAS, Sofia.