ML13316B982
| ML13316B982 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 01/27/1989 |
| From: | SOUTHERN CALIFORNIA EDISON CO. |
| To: | |
| Shared Package | |
| ML13316B981 | List: |
| References | |
| NUDOCS 8901310206 | |
| Download: ML13316B982 (64) | |
Text
3.3.3 MINIMUM WATER VOLUME AND BORON CONCENTRATION IN THE REFUELING WATER STORAGE TANK APPLICABILITTt-Applies to the inventory of borated refueling water.
OBJECTIVE:
To ensure immediate availability of safety injection and containment spray water of required quality.
SPECIFICATION:
When the Safety Injection System or the Containment Spray System is required to be operable, the refueling water tank shall be filled to at least elevation 50 feet with water 34 having a boron concentration of not less than 3750 ppa and not 4/1/77 greater than 4300 ppm.
BASIS:
The refueling water storage tank serves two purposes; namely:
(1) As a reservoir of borated water for accident mitigation
- purposes, (2) As a reservoir of borated water for flooding the refueling cavity during refueling.
Approximately 220,000 gallons of borated water is required to provide adequate post-accident core cooling and containment spray to maintain ca lated post-accident doses below the limits of 10 CFR 100 0 The refueling water storage tank filled to elevation 50 feet represents in excess of 240,000 4/1/77 A boron concentration of 3750 ppm is required 250 meet the requirements of postulated steam line break.
A maximum boron concentration of 4300 ppm ensures that the post-accident con nment sump water is maintained at a pH between 7.0 and The refueling tank capacity of 240,000 gallons is based on refueling volume requirements.
Sustained temperatures below 320F do not occur at San Onofre. At 32oF, boric acid is soluble up to approximately 34 4650 ppa boron. Therefore, no special provisions for 4/1/77 temperature control to avoid either freezing or boron precipitation are necessary.
References:
(1) Enclosure 1 "Post-Accident Pressure Reanalysis, San Onofre Unit 1" to letter dated January 19, 1977 in Docket No. 50-206.
(2) "Steam Line Break Accident Reanalysis, San Onofre Nuclear Generating Station, Unit 1, October 1976" submitted by letter dated December 30, 1976 in Docket No. 50-206.
(3) Additional information, San Onofre, Unit I submitted by letter dated March 24, 1977 in Docket No. 50-206.
8901310206 PDR ADOCK 802
-- 0 PNU Typo Revised:
7/9/82 3-35 Revised:
5/14/77
4.1.1 OPERATIONAL SAFETY ITEMS Analicability:
Applies to surveillance requirements for items directly related to Safety Standards and Limiting Conditions for Operation.
Obientive*
To specify the minimum frequency and type of surveillance to be applied to plant equipment and conditions.
Specification:
A. Reactor Trip System instrumentation shall be checked, tested, and calibrated as indicated in Table 4.1.1.
12/13/8 B. Equipment and sampling tests shall be as specified in Table 4.1.2.
C. The specific activity and boron concentration of the reactor coolant shall be determined to be within the 38 limits by performance of the sampling and analysis 12/20/77 program of Table 4.1.2., Item la.
D. The specific activity of the secondary coolant system shall be determined to be within the limit by performance of the sampling and analysis program of Table 4.1.2.,
Item lb.
E. All control rods shall be determined to be above the rod.
insertion limits shown in Figure 3.5.2.1 by verifying that each analog detector indicates at least 21 steps above the rod insertion limits, to account for-the instrument inaccuracies, at least once per shift during Startup conditions with Kgff equal to or greater than one.
F. The position of each rod shall be determined to be within the group demand limit and each rod position indicator shall be determined to be OPERABLE by verifying that the rod position indication system (Analog Detection System) and the step counter indication system (Digital Detection System) agree within 35 steps at least once per shift during Startup and Power Operation except during time intervals when the Rod Position Deviation Monitor is inoperable, then compare the rod position indication system (Analog Detection System) and the step counter indication system (Digital Detection System) at least once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
Go During MODE 1 or 2 operation each rod not fully inserted 83 in the core shall be determined to be OPERABLE by movement of at least 10 steps in any one direction at least once per 31 days.
H. Instrumentation shall be checked, tested, and calibrated U7 as indicated in Table 4.1.3.
2/13/88 SAN ONOFRE - UNIT 1 4-3 Revised: 12/21/88
MIN!IM aOUpNINT CHFCK AN13 SANPLTN ROF la. Reactor Coolant 1. Gross Activity At least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Samples Determination Required during Modes 3/
1, 2, 3 and 4.
- 2. Isotopic Analysis I per 14 days.
Required for DOSE EQUIVALENT only during Mode 1.
1-131 Concentration
- 3. Spectr copic 1 per 6 months(2) for ER" Required only during Determination Mode 1.
74
- 4. Isotopic Analy-a) Once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />,( 3) sis for Iodine whenever the specific Including 1-131, activity exceeds 1-133, and 1-135.
1.0 pCilgram DOSE EQUIVALENT 1-131 or 100/ E (1) pCi/gram.
b) One sample between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a THERMAL POWER change 31 exceeding 15 percent of 12/20/71 the RATED THERMAL POWER within a one hour period.
- 5. Boron concentration Twice/Week (1) E is defined in Section 1.0.
U17
/13/88 (2) Sample to be taken after a minimum of 2 EFPD and 20 days of POWER OPERATION have elapsed since reactor was last subcritical for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or longer.
(3) Until the specific activity of the reactor coolant system is restored within its limits.
SAN ONOFRE -'UNIT 1 4-7 Revised: 12/21/88
TABLE 4.1.2 (continued)
Check Frequency 1.b Secondary
- 1. Gross Activity At least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Coolant Determination Required only during Samples Modes 1, 2, 3 and 4.
- 2. Isotopic Analy-a) 1 per 31 days, whenever sis for DOSE the gross activity EQUIVALENT 1-131 determination indicates Concentration iodine concentrations greater than 10% of the 74 allowable limit.
12/6/83 Required only during Modes 1, 2, 3 and 4.
b) 1 per 6 months, whenever the gross activity determination indicates iodine concentrations below 10% of the allow able limit.
Required only during Modes 1, 2, 3, and 4.
4-8 Revised:
12/30/83 Typo Revision:
1/23/84
TABLE 4.1-.2 (continued)
Check Frequency
- 2. Safety
- a. Boron Concentration Monthly when the reactor is Injection critical and prior to return Water Samples of criticality when a period 12 of subcriticality extends 9/17/73 the test beyond 1 month
- 3. Control Rod
- a. Verify that all rods At each refueling shutdown Drop move from full out to full in, in less than 2.44 seconds 101 14/26/88
- 4. (Deleted) l61 I 6/11/81
- 5. Pressurizer
- a. Pressure Setpoint At each refueling shutdown Safety Valves
- 6. Main Steam
- a. Pressure Setpoint At each refueling shutdown Safety Valves
- 7. Main Steam
- a. Test for Operability At each refueling shutdown Power Operated Relief Valves
- 8. Trisodium
- a. Check for system At each refueling shutdown Phosphate availability as Additive delineated in Technical Speci fication 4.2
- 9. Hydrazine
- a. Hydrazine concentra-Once every six months when Tank Water tion the reactor is critical and Samples prior to return of critica lity when a period of sub-34 criticality extends the test 4/1/77 interval beyond six months
- 10. Transfer
- a. Verify that the fuse Monthly, when the reactor is Switch No. 7 block for breaker critical and prior to 8-1181 to MCC 1 is returning reactor to criti removed cal when period of subcriti cality extended the test interval beyond one month 4-9 Revised: 5/26/88
ATTACHMENT 2 PROPOSED TECHNICAL SPECIFICATIONS 3.3.3 MINIMUM BORON CONCENTRATION IN THE REFUELING HATER STORAGE TANK (RWST)
AND SAFETY INJECTION (SI) LINES AND MINIMUM RHST WATER VOLUME APPLICABILIT:
MODES 1, 2, 3 and 4; or as described in Specification 3.2.
OBJECTIVE:
To ensure immediate availability of borated water from the RWST for safety injection, containment spray or emergency boration.
SPECIFICATION: a. The RWST shall be OPERABLE with a level of at least plant elevation 50 feet of water having a boron concentration of not less than 3750 ppm and not greater than 4300 ppm.
- b. The safety injection (SI) lines from the RWST to MOV 850 A, B, and C, with the exception of lines common to the feedwater system, shall be OPERABLE with a boron concentration of not less than 1500 ppm and not greater than 4300 ppm.
ACTION:
A. With the refueling water storage tank inoperable, restore the tank to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
B. With one or both SI lines inoperable due to boron concentration of less than 1500 ppm, restore the SI lines to OPERABLE status within I hour or be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
BASIS:
The refueling water storage tank serves three purposes; namely:
g (1) As a reservoir of borated water for accident mitigation
- purposes, (2) As a reservoir of borated water for flooding the refueling cavity during refueling.
(3) As a deluge for fires in containment.
Approximately 220,000 gallons of borated water is required to provide adequate post-accident core cooling and containment spray to maintain cal plated post-accident doses below the limits of 10 CFR 100('.
The refueling water storage tank filled to a plant elevation 50 feet represents in excess of 240,000 gallons.
A boron concentration of 3750 ppm in the RWST and 1500 ppm in the SI lines is required t miet the requirements of a postulated steam line break.
( Y A maximum boron concentration of 4300 ppm ensures that the post-accident containment sump water is maintained at a pH between 7.0 and 1.503).
The refueling tank capacity of 240,000 gallons is based on refueling volume requirements and includes an allowance for water not usable because of tank discharge line location.
Sustained temperatures below 32*F do not occur at San Onofre.
At 32*F, boric acid is soluble up to approximately 4650 ppm boron. Therefore, no special provisions for temperature control to avoid either freezing or boron precipitation are necessary.
References:
(1) "Post-Accident Pressure Reanalysis, San Onofre Unit 1" to letter dated January 19, 1987 in Docket No.
50-206 (2) "Main Steamline Break Analysis, San Onofre Nuclear Generating Station, Unit 1, August 1988" (3)
Additional information, San Onofre, Unit 1 submitted by letter dated March 24, 1987 in Docket No. 50-206 (4)
Accident Evaluation to Support Cycle X Operation for San Onofre Nuclear Generating Station Unit 1, January 1989
4.1.1 OPERATIONAL SAFETY ITEMS Aolicability:
Applies to surveillance requirements for items directly related to Safety Standards and Limiting Conditions for Operation.
ObJective:
To specify the minimum frequency and type of surveillance to be applied to plant equipment and conditions.
Specification:
A. Reactor Trip System instrumentation shall be checked, tested, and calibrated as indicated in Table 4.1.1.
B. Equipment and sampling tests shall be as specified in Table 4.1.2.
C. The specific activity and boron concentration of the reactor coolant shall be determined to be within the limits by performance of the sampling and analysis program of Table 4.1.2., Item la.
D. The specific activity of the secondary coolant system shall be determined to be within the limit by performance of the sampling and analysis program of Table 4.1.2.,
Item lb.
E. All control rods shall be determined to be above the rod insertion limits shown in Figure 3.5.2.1 by verifying that each analog detector indicates at least 21 steps above the rod insertion limits, to account for the instrument inaccuraces, at least once per shift during Startup conditions with Keff equal to or greater than one.
F. The position of each rod shall be determined to be within the group demand limit and each rod position indicator shall be determined to be OPERABLE by verifying that the rod position indication system (Analog Detection System) and the step counter indication system (Digital Detection System) agree within 35 steps at least once per shift during Startup and Power Operation except during time intervals when the Rod Position Deviation Monitor is inoperable, then compare the rod position indication system (Analog Detection System) and the step counter indication system (Digital Detection System) at least once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
G. During MODE 1 or 2 operation each rod not fully inserted in the core shall be determined to be OPERABLE by movement of at least 10 steps in any one direction at least once per 31 days.
H. Instrumentation shall be checked, tested, and calibrated as indicated in Table 4.1.3.
TABLE 4.1.2 MINIMUM EOUIPMENT CHECK AND SAMPLING FREOUENCY Check Frequency la. Reactor Coolant 1. Gross Activity At least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Samples Determination Required during Modes 1, 2, 3 and 4.
- 2. Isotopic Analysis 1 per 14 days. Required for DOSE EQUIVALENT only during Mode 1.
1-131 Concentration
- 3. Spectroscopic 1 per 6 months( 2) for E(1)
Required only during Determination Mode 1.
- 4. Isotopic Analy-a) Once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />,( 3) sis for Iodine whenever the specific Including 1-1,31, activity exceeds I-133, and 1-135.
1.0 mCi/gram DOSE EQUIVALENT 1-131 or 100/ E (1) mCi/gram.
b) One sample between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a THERMAL POWER change exceeding 15 percent of the RATED THERMAL POWER within a one hour period.
- 5. Boron concentration Twice/Week (1) E is defined in Section 1.0.
(2) Sample to be taken after a minimum of 2 EFPD and 20 days of POWER OPERATION have elapsed since reactor was last subcritical for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or longer.
(3) Until the specific activity of the reactor coolant system is restored within its limits.
III
TABLE 4.1.2 (continued)
Check Frequency l.b Secondary
- 1. Gross Activity At least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
coolant Determination Required only during Samples Modes 1, 2, 3 and 4.
- 2. Isotopic Analy-a) 1 per 31 days, whenever sis for DOSE the.gross activity EQUIVALENT 1-131 determination indicates Concentration iodine concentrations greater than 10% of the allowable limit. Required only during Modes 1, 2, 3 and 4.
b) 1 per 6 months, whenever the gross activity determination indicates iodine concentrations below 10% of the allowable limit. Required only during Modes 1, 2, 3, and 4.
TABLE 4.1.2 (continued)
Check Frequency
- 2. Safety
- a. Boron Concentration Monthly when the reactor is Injection Line critical and prior to return and RWST Water of criticality when a period Samples of subcriticality extends the test beyond 1 month
- 3. Control Rod
- a. Verify that all rods At each refueling shutdown Drop move from full out to full in, in less than 2.44 seconds
- 4. (Deleted)
- 5. Pressurizer
- a. Pressure Setpoint At each refueling shutdown Safety Valves
- 6. Main Steam
- a. Pressure Setpoint At each refueling shutdown Safety Valves
- 7. Main Steam
- a. Test for Operability At each refueling shutdown Power Operated Relief Valves
- 8. Trisodium
- a. Check for system At each refueling shutdown Phosphate availability as Additive delineated in Technical Specification 4.2
- 9. Hydrazine
- a. Hydrazine concentra-Once every six months when Tank Water tion the reactor is critical and Samples prior to return of critica lity when a period of subcriticality extends the test interval beyond six months
- 10. Transfer
- a. Verify that the fuse Monthly, when the reactor is Switch No. 7 block for breaker critical and prior to 8-1181 to MCC 1 is returning reactor to criti removed cal when period of subcriti cality extended the test interval beyond one month
- 11.
RWST Contained a. Verify volume Monthly when the reactor is Water Volume
> 50 ft. plant critical and prior to return elevation of criticality when a period of subcriticality extends the surveillance beyond 1 month
ATTACHMENT 3 ACCIDENT ANALYSES
ACCIDENT EVALUATION TO SUPPORT CYCLE 10 OPERATION FOR SAN ONOFRE NUCLEAR GENERATING STATION UNIT 1 JANUARY 1989 Revision 0
CONTENTS 1.0 Introduction 2.0 Operating Plant Parameters for 20% Tube Plugging 3.0 Safety Evaluation 3.1 Non-LOCA Safety Evaluation 3.1.1
Background
3.1.2 Reactor Protection and Engineered Safeguards Feature Setpoints 3.1.3.1 Uncontrolled RCCA Bank Withdrawal from a Subcritical Condition 3.1.3.2 Uncontrolled RCCA Bank Withdrawal at Power 3.1.3.3 Startup of an Inactive Reactor Coolant Loop 3.1.3.4 Addition of Excess Feedwater 3.1.3.5 Large Load Increase 3.1.3.6 Dropped Rod 3.1.3.7 Control Rod Ejection 3.1.3.8 Loss of Coolant Flow 3.1.3.9 Loss of Load 3.1.3.10 Loss of Normal Feedwater 3.1.3.11 Feedline Break 3.1.3.12 Steamline Break Mass/Energy Release Inside and Outside Containment 3.1.4 Non-LOCA Events Reanalyzed 3.1.4.1 Steamline Break Core Response 3.1.4.2 Locked Rotor/Shaft Break (To be provided at a later date) 3.1.5 Conclusions of Non-LOCA Safety Evaluation 3.2 LOCA Evaluation (To be provided at a later date) 3.3 Steam Generator Tube Rupture 4.0 Conclusions
ACCIDENT EVALUATION TO SUPPORT CYCLE 10 OPERATION FOR SAN ONOFRE NUCLEAR GENERATING STATION UNIT 1 Revision 0
1.0 INTRODUCTION
San Onofre Unit 1 (SONGS-1) has completed its ninth cycle of operation and is in a refueling outage in preparation for Cycle 10 startup in early 1989.
Due to tube degradation, some of the tubes in the San Onofre 1 model 27 steam generators have been removed from service through plugging while others have been repaired and returned to service through sleeving.
Plugging a steam generator tube decreases the fluid volume in the steam generator tube bundle region, reduces the primary to secondary heat transfer capability, and increases the pressure loss across the steam generator tube bundle. Sleeving maintains the active heat transfer of the tube, but the heat transfer capability is reduced and an increased pressure drop across the sleeved tube results. Consequently, sleeving a sufficient number of tubes has the same effect as plugging a tube, and an hydraulic equivalence between sleeving and plugging can be made for analysis purposes.
In the safety analyses for SONGS-1, the effect of steam generator tube sleeving and plugging may be modeled through a reduction in flow with an increase in loop flow resistance. The effect of reduced primary to
.secondary heat transfer capability may also adversely affect the analysis results. Consequently, the safety analyses are performed with an assumed equivalent level of tube plugging such that the actual equivalent levels of plugging are conservatively modeled.
During the cycle 10 refueling outage, additional steam generator tubes were plugged such that the actual levels of equivalent plugging how exceed the previously analyzed values by a small amount. The actual plugging and sleeving levels at SONGS-1 are provided below:
B C
Tubes Plugged 11.47%
12.07%
13.05%
Tubes Sleeved (Equiv.)
3.06%
2.90%
2.95%
Total Equiv. Plugging 14.53%
14.97%
16.00%
The equivalent plugging for the sleeved tubes is based on a ratio of 18.6 sleeves per plug.
-1
San Onofre 1 operates at a reduced reactor coolant vessel average temperature (Tavg=551.5 0F).
Accident analyses for SONGS-1 support operation at the reduced Tavg for equivalent tube plugging levels up to 15% maximum in any steam generator. The analyses also support up.to.20% maximum tube.
plugging at the nominal Tavg (575.50 F).
Loss of Coolant Accident'-(LOCA) analyses results with the Emergency Core Cooling System (ECCS) evaluation model used for SONGS-1, indicate higher peak clad temperatures for reductions in the vessel average temperature.
Therefore the 20% maximum tube plugging LOCA analysis may not bound plant operation with increased tube plugging at the reduced vessel average temperature condition.
Since the 15% tube plugging level has been exceeded by the tube plugging performed at the cycle 10 outage, Southern California Edison has requested Westinghouse to perform the safety analyses necessary to support steam generator tube plugging levels up to 20% in any steam generator. A new LOCA analysis is required to support an increase in steam generator tube plugging.
The other accidents and transients described in Chapter 15 of the SONGS-1 Updated Final Safety Analysis Report (UFSAR) must also be evaluated to determine if the current analyses continue to be applicable for operation with-20% tube plugging and reduced Tavg. The primary effect of increased tube plugging on the non-LOCA transients is to reduce Thermal Design Flow which is used as an input to the initial conditions of the analysis.
Southern California Edison also requested Westinghouse to evaluate other changes to the plant which would affect the accident analyses. The analyses in this report also include the effect of an additional time delay in delivery of safety injection to the reactor coolant system due to postulated.
voltage degradation and boron concentration of 1500 ppm in the Safety Injection lines.
The following sections of this report present the results of the accident analyses and evaluations to support operation of San Onofre Unit 1 at an equivalent 20% steam generator tube plugging, reduced Vessel average coolant temperature, and additional SI time delay for all events except for LOCA and shaft break. The reanalysis of these events is not complete at this time, but will be provided at a later date.
2.0 OPERATING PLANT PARAMETERS FOR 20% TUBE PLUGGING This section describes the baseline Operating Plant Parameters which form the basis of the various design and safety analyses performed by Westinghouse. For the San.Onofre 20% tube plugging return to power evaluation, the parameters were generated based on certain key design input values. It was found, based on operating data, a thermal-hydraulic model of the plant, ;'and available margins, that Thermal Design Flow-can be maintained at 65,000 gpm/loop with the increased tube plugging. Other input assumptions were a vessel average temperature (T-avg) of 551.5*F and.uniform 20% tube plugging.
Some of the key parameters which are used in the analysis are as follows:
NSSS Power, MWt 1351 Reactor Power, MWt 1347 Thermal Design Flow, gpm/loop 65000 Reactor Coolant Pressure, psia 2100 Core Bypass Flow, %
4.5 Vessel Outlet Temp., OF 575.8 Vessel Average Temp., *F 551.5 Vessel Inlet Temp., "F 527.2 Steam Temperature, *F 476.4 Steam Pressure, psia 547 SG Fouling Factor, hr-ft2-*F/BTU 0.00028 SG Tube'Plugging, % (Uniform) 20 These parameters are input to the safety analyses as appropriate.
3.0 SAFETY EVALUATION 3.1 NON-LOCA SAFETY EVALUATION 3.1.1
Background
This section provides the non-LOCA safety-evaluation to support San.Onofre Nuclear Generating Station 1 (SONGS 1) operation on the Reduced Tavg Program with up to 20% tube plugging level in any one steam generator.
Also included in this safety evaluation is the impact of an increase in the safety injection delay time assumed in the steamline break analysis.
The current non-LOCA safety analyses and evaluations for SONGS 1 (Reference 1) support operation at the following conditions:
I. Nominal Tavg Program Full Core Power
= 1347 MWt Full Power Tavg
= 575.15*F RCS Pressure
= 2100 psia Thermal Design Flow
= 65000 gpm/loop S.G. Tube Plugging Level
< 20%
Full Power Steam Pressure = 673.4 psia II. Reduced Tavg Program Full Core Power
= 1347 MWt Full Power Tavg
= 551.5*F RCS Pressure
= 2100 psia Thermal Design Flow
= 67300 gpm/loop S.G. Tube Plugging Level < 15%
Full Power Steam Pressure = 576.2 psia The primary effect of the increased steam generator tube plugging level for the Reduced Tavg Program operation is to decrease the Thermal Design Flow.
Although the increased tube plugging level also reduces the steam generator heat transfer area and the primary coolant mass inventory, the decrease due to the 5% increase in tube plugging level is not considered significant to
-the current non-LOCA safety analyses and evaluations., The new operating.
conditions of the Reduced Tavg Program with 20% steam generator tube plugging level are as follows:
III. Reduce Tavg Program (20% Tube Plugging)
Full Core Power
= 1347 MWt Full Power Tavg
= 551.5*F RCS Pressure
= 2100.psia Thermal Design Flow
= 65000 gpm/loop S.G. Tube Plugging Level
< 20%
Full Power Steam Pressure = 547.0 psia The impact of the reduced Thermal Design Flow for SONGS 1 operation on the Reduced Tavg Program for the non-LOCA transients is addressed in the fol owing sections.
Tablel,presents'the non-LOCA transients addressedrin,.t this safety evaluation. The safety evaluation is based on the operation conditions listed above for the Reduced Tavg Program with 20% Steam Generator Tube Plugging Level.
This safety evaluation is based on a maximum effective steam generator tube plugging level of 20%. All combinations of tube plugging and sleeving yielding an effective plugging level of less than 20% are bounded by this safety evaluation. As discussed in the following sections, no reanalyses are required to support the increase in tube plugging level for Reduced Tavg Program operation for SONGS 1. However, reanalysis is required to address the increase in safety injection delay time for the steamline break core response analysis.
3.1.2 Reactor Protection System and Engineered Safeguards Feature Setpoints The Reactor Protection System and Engineered Safeguards Feature setpoints assumed in the current safety analyses remain valid for the increase in steam generator tube plugging level for Reduced Tavg Program operation for OSONGS 1. The current core thermal safety limits are based on a full core power of 1347 MWt and a Thermal Design Flow of 195000 gpm. The Variable Low Pressure and the Overpower reactor trip functions provide protection for the core thermal safety limits (Figure 1).
Since the reduced Thermal Design Flow associated with the increase in steam generator tube plugging for the Reduced Tavg Program operation for SONGS 1 is not less than 195000gpm, the-currentcore thermal safety limits remain valid. The steam,!,
generator safety valve limit line, along with the Overpower reactor trip function, provides a boundary for the protection required by the Variable Low Pressure reactor trip. With the reduction in nominal full power steam pressure for the increased tube plugging level, the range of protection required by the Variable Low Pressure trip is increased. A reduced steam pressure would cause the steam generator safety valve line of Figure 1 to shift downward. However, the current steam generator safety valve limit line is conservative and bounds the steam generator safety valve limit line associated with the reduced nominal full load steam pressure of the Reduced Tavg Program with 20% tube plugging. Thus, no changes to the Variable Low Pressure reactor trip equation are required to support the conditions associated with the Reduced Tavg Program with 20% steam generator tube plugging.
3.1.3 Non-LOCA Events Evaluated 3.1.3.1 Uncontrolled RCCA Bank Withdrawal From a Subcritical Condition This event, as discussed in UFSAR Section 15.8.1, is examined to show that the core and reactor coolant system are not adversely-affected. This is done by showing that the DNBR limit is met and that the peak RCS pressure does not exceed 110% of design.
The uncontrolled RCCA bank withdrawal from a subcritical condition was recently analyzed to support SONGS 1 Cycle 9 extended operation (Reference 2).
The analysis assumed a RCS flow corresponding to 20% steam generator tube plugging level to bound the tube plugging level associated with the Nominal Tavg Program operation (20%) and the Reduced Tavg Program operation (15%).
Since the no load temperature is the same for both Tavg programs, the analysis documented in (Reference 2) was applicable for both Tavg programs. As such, the analysis to support the Cycle 9 extended operation also supports the Reduced Tavg Program operation with 20% steam generator tube plugging level since the reduced Thermal Design Flow (195000 gpm) for the increased tube plugging level for Reduced Tavg Program operation is not less than the Thermal Design Flow (195000) for Nominal Tavg Program with 20% tube plugging level.
Thus, the conclusions presented i.n the UFSAR remain valid.
3.1.3.2 Uncontrolled RCCA Bank Withdrawal at Power The current analyses for the uncontrolled RCCA bank withdrawal at power transient to support the Nominal Tavg Program with 20% tube plugging operation and the Reduced Tavg Program with 15% tube plugging operation are presented in-UFSAR Section 15.8.2. This event is primarily performed to demonstrate the adequacy of the reactor protection system to protect the core thermal-safety-limits. This.evaluation of-the uncontrolled RCCA bank,.
withdrawal at power transient to support the increase in tube plugging for the Reduced Tavg Program operation assumes no change to the Variable Low Pressure reactor trip function used in the UFSAR analyses. As stated previously, the core thermal safety limits remain unchanged.
The UFSAR analysis for the Nominal Tavg Program with 20% tube plugging is applicable for SONGS I operation on Reduced Tavg Program with 20% tube plugging. The Thermal Design Flows for the two conditions are the same.
The higher initial Tavg associated with the Nominal Tavg Program is conservative for the DNB evaluation of the cases where reactor trip is provided by the Power Range High Neutron Flux, high setting. It is expected that, since the Nominal Tavg Program RWAP analysis showed that the Variable Low Pressure reactor trip is adequate for Nominal Tavg Program 20%
tube plugging operation, the Variable Low Pressure reactor trip equation is adequate for Reduced Tavg Program 20% tube plugging operation. The only difference is that, with the Reduced Tavg Program, it will take longer to reach the Variable Low Pressure setpoint. This is because the Variable Low Pressure reactor trip function is based on Tavg and Delta-T. The lower Tavg of the Reduced Tavg Program puts operation further.away from the setpoint (see Figure 1).
Although it will take longer to reach the Variable Low Pressure trip setpoint, the Variable Low Pressure reactor trip will provide protection of the core thermal safety limits. Sensitivity studies show that the increased time to reactor trip does not retard the ability of the Variable Low Pressure reactor trip, in combination with the Power Range High Neutron Flux, high setting, reactor trip, to protect the core thermal safety limits. As such, the uncontrolled RCCA bank withdrawal at power safety analysis for Nominal Tavg Program with 20% tube plugging supports SONGS 1 operation on the Reduced Tavg Program with 20% steam generator tube plugging. Thus, the conclusions presented in the UFSAR remain valid.
3.1.3.3 Startup of an Inactive Reactor Coolant Loop This transient is examined in UFSAR Section 15.9 to determine the effect on core integrity. Core integrity is assured by calculating a minimum DNBR above the limit value. An inadvertent startup of an idle reactor coolant pump results in the injection of cold water into the core. This causes an increase in reactivity due to the increase in moderator density.
This incident need not be addressed due to the Technical Specification restrictions which prohibit operation with a loop out of service for power
.levels greater than 10 percent. However, a brief discussion of the impact of Reduced Tavg Program with 20% tube plugging level operation is included. Previous evaluations presented in the SONGS 1 Cycle 8 Reload Safety Evaluation (Reference 3) support operation on the Nominal Tavg Program with 20% tube plugging and Reduced Tavg with 15% tube plugging.
The only difference between the Nominal Tavg Program and Reduced Tavg
-Program operations isthe initial Tavg.
(The Thermal Design Flows are now the same for the two conditions due to the increase in tube plugging for the Reduced Tavg Program.)
The higher initial Tavg associated with the Nomi-nal Tavg Program bounds the initial Tavg of the Reduced Tavg Program with respect to the DNB evaluation. As such, the evaluation of the startup of an inactive reactor coolant loop transient to support Nominal Tavg Program with 20% tube plugging level presented in the Cycle 8 Reload Safety Evaluation (Reference 3) is bounding for SONGS 1 operation on the Reduced Tavg Program with 20% steam generator tube plugging level.
Thus, the conclusions presented in the UFSAR and Reference 3 remain valid.
3.1.3.4 Addition of Excess Feedwater This event, as discussed in UFSAR Section 15.1.2, is examined to show that the core and reactor coolant system are not adversely affected. This is done by showing that the DNBR limit is met and that the peak pressure does not exceed 110% of design pressure.
The addition of excessive feedwater is an excessive heat removal incident which results in a power increase due to moderator feedback. UFSAR Section 15.1.2 presents two cases. The first case assumes that all three
'feedwater control valves fully open together at full load. The second case assumes the startup of a feedwater pump with one pump already running -while at 50 percent power; the control valves are in manual.
The results presented in the UFSAR show that there is no significant reduction in core inlet temperature and there is very little response to this condition by the Reactor Coolant System for both cases. Manual trip of the reactor is assumed to occur following high level alarms on the steam generators. The core never approaches the DNBR safety limit, and the RCS pressure never exceeds 110% of design during this transient.
As the case with the startup of an inactive loop event, the addition of excess feedwater transient was evaluated for Nominal Tavg Program operation with 20% tube plugging and for Reduced Tavg Program with 15% tube plugging in the Cycle 8 Reload Safety Evaluation (Reference 3).
The Nominal Tavg Program with 20% tube plugging evaluation bounds SONGS 1 operation on the Reduced Tavg Program with 20% tube plugging since the Cycle 8 evaluation assumed a higher Tavg, which is conservative. Thus, the conclusions presented in 'the UFSAR and Reference 3 remain valid.
3.1.3.5 Large Load Increase This event, as discussed in UFSAR Section 15.1.3, is examined to show that the core and reactor coolant system are not adversely affected. This is done by showing that the DNBR limit is met and that the peak pressure does not exceed 110% of design pressure.
An excessive load increase event, in which the steam load exceeds the core power, results in a decrease in reactor coolant system temperature which may-lead to a power increase-due to moderator feedback. The maximum thermal power level evaluated in the UFSAR corresponds to the situation with the turbine control valves fully open. The power level associated with the Reduced Tavg Program also corresponds to the situation with the turbine control valves fully open.
This eliminates the possibility of a large load increase above this power level.
Therefore, as was shown in UFSAR Section 15.1.3, a step load increase of 30 percent to the maximum achievable steam flow, is not expected to result in a reactor trip since sufficient margin to the reactor protection setpoints (including uncertainties) exists. If required, protection for this event is provided by the overpower and variable low pressure reactor trip functions. As stated previously, the adequacy of the protection was verified in the, uncontrolled RCCA bank withdrawal at power evaluation for Reduced Tavg Program operation with 20% tube plugging.
The large load increase transient was evaluated for Nominal Tavg Program operation with 20% tube plugging and for Reduced Tavg Program operation with 15% tube plugging in the Cycle 8 Reload Safety Evaluation (Reference 3).
The Nominal Tavg Program with 20% tube plugging evaluation bounds SONGS 1 operation on the Reduced Tavg Program with 20% tube plugging since the Cycle 8 evaluation assumed a higher Tavg, which is conservative. Thus, the conclusions presented in the-UFSAR and Reference 3 remai-n valid.
3.1.3.6 Dropped Rod This event is examined to show that the core and reactor coolant system are not adversely affected. This is done by showing that the DNBR limit is met and that the peak pressure does not exceed 110% of design pressure. UFSAR Section 15.8.3 presents the safety analyses for the dropped rod event.
The safety analyses presented in the UFSAR address two modes of operation for SONGS 1, with turbine runback and without turbine runback. The analysis to address the with turbine runback case supports both Nominal Tavg Program and Reduced Tavg Program operations. A conservative high initial Tavg associated with the Nominal Tavg Program and a conservative low Thermal Design Flow associated with 20% steam generator tube plugging were assumed to bound both set of operating conditions. The analysis to address the without turbine runback case supports only the Reduced Tavg Program operation. The analysis assumed a conservative low Thermal Design Flow (195000 gpm) associated with 20% tube plugging. As such, SONGS 1 operation with a Reduced Tavg Program with 20% steam generator tube plugging is supported by the UFSAR analysis.
Thus, the conclusions presented in the UFSAR remain valid.
3.1.3.7 Control Rod Ejection This incident, as presented in UFSAR Section 15.11, is examined to ensure that the average fuel pellet enthalpy remains below the limit, that the hot spot clad temperature remains below 2450*F,- that the peak reactor coolant pressure is less than a value which would cause stresses to exceed the Faulted Conditions stress limit, and that fuel melting is limited to less than 10% at the hot spot.
This event was recently reanalyzed to support the SONGS 1 Cycle 9 extended operation (Reference 2).
All four cases of the rod ejection safety analysis were reanalyzed (Hot Zero Power at Beginning of Core Life, Hot Full Power at Beginning of Core Life, Hot Zero Power at End of Core Life, and Hot Full Power at End of Core Life).
The analysis was performed to bound both the Nominal Tavg Program operation with 20% tube plugging and the Reduced Tavg Program operation with 15% tube plugging. This was accomplished by assuming initial Tavg's associated with the Nominal Tavg Program and conservative RCS flows associated with 20% steam generator tube plugging. As such, SONGS 1 operation with a Reduced Tavg Program with 20%
tube plugging is supported by the analysis presented in the Cycle 9 extended operation report (Reference 2).
Thus, the conclusions presented in the UFSAR remain valid.
3.1.3.8 Loss of Coolant Flow This event, as discussed in UFSAR Section 15.7.1, is examined to "demonstrate that the DNB design-safety limit is met. The UFSAR presents a bounding safety analysis to support SONGS 1 operation with.the Nominal :Tavg Program with 20% steam generator tube plugging and to support operation with the Reduced Tavg Program with 15% steam generator tube plugging. The safety analysis is also-used to bound the increase in tube-plugging level for the Reduced Tavg Program. The conservative direction for initial conditions for temperature and flow for the loss of coolant flow analysis is to assume a high Tavg and a low Thermal Design Flow. The safety analysis assumed an initial Tavg associated with the Nominal Tavg Program and a RCS Thermal Design Flow (195000 gpm) associated with 20% tube plugging. As such, SONGS 1 operation with a Reduced Tavg Program with 20%
steam generator tube plugging level is supported by the loss of flow safety analysis presented in the UFSAR. Thus, the conclusions presented in the UFSAR remain valid.
3.1.3.9 Loss of Load This event, as discussed in UFSAR Section 15.3, is examined to show that the core and reactor coolant system are not adversely affected. This is done by showing that the DNBR limit is met and that the peak pressure does not exceed 110% of design pressure.
.The loss of load in combination with failure of the steam dump system causes an increase in steam generator temperature and pressure. This in turn causes an increase in RCS temperature and pressure. As described in UFSAR Section 15.3, core protection is provided by High Pressurizer Water Level, High Pressurizer Pressure, or Variable Low Pressure reactor trip.
The loss of load event was evaluated in the Cycle 8 Reload Safety Evaluation (Reference 3) to support SONGS 1 operation with a Nominal Tavg Program with 20% steam generator tube plugging level and with a Reduced Tavg Program with 15% steam generator tube plugging level.
For the loss of load event, the conservative direction on initial conditions for temperature and flow is to assume a high Tavg and a low RCS flow. The Tavg associated with a Nominal Tavg Program bounds the Tavg associated with a Reduced Tavg Program and the assumed Thermal Design Flow (195000 gpm) associated with 20% tube plugging remains the same for Reduced Tavg Program operation with 20% tube plugging. As such, SONGS 1 operation with a Reduced Tavg Program with 20% steam generator tube plugging level is supported by the Nominal Tavg Program operation with 20% tube plugging evaluation presented in the Cycle 8 Reload Safety Evaluation (Reference 3).
Thus, the conclusions presented in the UFSAR and Reference 3 remain valid.
3.1.3.10 Loss of Normal Feedwater This event, as discussed in UFSAR Section 15.5, is examined to show that the core and reactor coolant system are not adversely affected. This is done by showing that the DNBR limit-is-met, that the -peak pressure does not exceed 110% of design pressure, and that the pressurizer does not become water solid.
The current loss of normal feedwater safety analyses presented in Reference 4 assumed conservative initial conditions to bound both Nominal Tavg Program with 20% tube plugging operation and Reduced Tavg Program with 15% tube plugging. The conservative direction for initial conditions for temperature and RCS flow is to assume a high Tavg and a low RCS flow. As used in the Reference 4 analysis, the high Tavg of the Nominal Tavg Program operation is bounding for the Reduced Tavg Program. Also the RCS Thermal Design Flow (195000 gpm) corresponding to 20% tube plugging is the conservative assumption for flow and is applicable for the increased tube plugging level (20%) for the Reduced Tavg Program operation. As such, SONGS 1 operation with the Reduced Tavg Program with 20% steam generator tube plugging level is supported by the current loss of normal feedwater safety analyses presented in Reference 4. Thus, the conclusions presented in the UFSAR and Reference 4 remain valid.
3.1.3.11 Feedline Break This event, as discussed in UFSAR Section 15.6, is examined to ensure that the reactor coolant and main steam pressures are maintained below 110% of their design pressures and the core remains in a coolable geometry.
The current feedline break safety analyses presented in Reference 4 assumed conservative initial conditions to bound both Nominal Tavg Program with 20%
tube plugging operation and Reduced Tavg Program with.15% tube. plugging.
The conservative direction for initial conditions for temperature and RCS flow is to assume a high Tavg and a low RCS flow. As used in the Reference 4 analyses, the high Tavg of the Nominal Tavg Program operation is bounding for the Reduced Tavg Program. Also the RCS Thermal Design Flow (195000 gpm) corresponding to 20% tube plugging is the conservative assumption for flow and is applicable for the increased tube plugging level (20%) for the Reduced Tavg Program operation. As such, SONGS 1 operation with the Reduced Tavg Program with 20% steam generator tube plugging level
-is supported by the current feedline break safety analyses presented in Reference 4. -Thus, the conclusions presented -in the UFSAR and Reference 4 remain valid.
3.1.3.12 Steam Line Break Mass/Energy Release Inside and Outside Containment Mass/energy releases following a steamline rupture inside containment are used to determine the maximum pressure.,peaks for.containment integrity, evaluations. The mass/energy releases following-a steamline-rupture outside containment are used to determine the temperature profiles for qualification of equipment. The temperature profile is a function of both the steam blowdown and the compartment in which the equipment is located.
The outside containment steamline break mass/energy analysis (Reference 5) provides information for use in evaluating the effects of steam generator tube bundle uncovery -and the-associated superheated steam.generation for areas outside containment.
The increase in steam generator tube plugging level is acceptable since the mass/energy release analyses assumed heat transfer characteristics to support SONGS 1 steam generator tube plugging levels.
Also, the analyses assumed initial Tavg's corresponding to the Nominal Tavg Program, which bound Reduced Tavg Program operation since higher Tavg is conservative. As such, the steamline break mass/energy release analyses support Reduced Tavg Program operation with 20% steam generator tube plugging.
Also, the increase in safety injection delay time of 4 seconds does not significantly impact the mass/energy releases for a steamline break inside containment. Due to the low shutoff head (around 1190 psia) of the safety injection pumps, safety injection water reaching the RCS is typically delayed beyond the electrical and mechanical delays. An increase in the Oelectrical and mechanical delays of safety injection of 4 seconds would not significantly delay the time that safety injection water reaches the RCS.
Also, the mass/energy releases are not very sensitive to any resulting small delay in time that safety injection would reach the RCS. As such, the steamline break mass/energy release analyses are applicable for an increase in the safety injection delay time of 4 seconds.
3.1.3.13 References
- 1. Updated Final Safety Analysis Report (UFSAR) for San Onofre 1.
- 2. Skaritka, 3. (Ed.), "Evaluation of the San Onofre Unit 1 Cycle 9 Extended Operation," November, 1988.
- 3. Skaritka, 3. (Ed.), "Reload Safety Evaluation San Onofre Nuclear Generating Station Unit 1, Cycle 8, January, 1980.
Skaritka, 3. (Ed.), "Reload Safety Evaluation San Onofre Nuclear Generating Station Unit 1, Cycle 8, Revision 1, October, 1980.
Skaritka, J. (Ed.), "Reload Safety Evaluation San Onofre Nuclear Generating Station Unit 1, Cycle 8, April, 1981.
- 4. "SCE SONGS Unit 1 Third Auxiliary Feedwater Pump Reanalysis,"
SCE-87-612, Letter from L. E. Elder (W) to 3. L. Rainsberry (SCE),
August 7, 1987.
"San Onofre Unit 1 LONF/FLB Reanalysis," SCE-86-540, Letter from L. E. Elder (W) to 3. L. Rainsberry (SCE), April 8, 1986.
- 5. Rinkacs, W. 3., "SCE SONGS Unit 1 Steamline Break Outside Containment Mass/Energy Release Analysis," WCAP-11294, (Westinghouse Proprietary Class 2), September, 1986.
TABLE 1 SONGS 1 Non-LOCA Transients Transient Uncontrolled RCCA Bank Withdrawal From a Subcritical Condition Uncontrolled RCCA Bank Withdrawal at Power Startup of an Inactive Loop Addition of Excess Feedwater Large Load Increase Dropped Rod Control Rod Ejection Loss of Coolant Flow Steam Line Break Core Response Loss of Load Loss of Normal Feedwater Feedline Break Locked Rotor/Pump Shaft Break (To be provided later)
Steam Line Break Mass/Energy Release Outside Containment Steam Line Break Mass/Energy Release Inside Containment so PI P2 Pp A PS 13 agIR and Vessel Exit Boiling Limits Overpower Protection steam p
/.S Generator Safety Valve 5*
Line P/
P/
/
40 Variable Low Pressure Tripa Lines P2 a1775 psi&
P3 *1900 psi&
A: Nominal Tavg Program P4 2100 psi&
Full Power Operating Point 1
~
2250 psia Full Power Operating Point B: Reduced Tavg Program 24 520 540 560 MD 600 620 640 VESSEL AVERAGE TEMPERATURE (OF)
FIGURE I OVERPOWER AND OVERTEMPERATURE PROTECTION DIAGRAM EXISTING VARIABLE LOW-.PRESSURE REACTOR TRIP FU NCTION 15
3.1.4 Non-LOCA Events Reanalyzed Although the increase in steam generator tube plugging level to 20% for SONGS 1 operation on the Reduced Tavg Program does not require any specific reanalyses (except for the locked rotor/shaft break event which will be provided later), the other plant parameter change discussed in Section 3.1.1 requires reanalysis of two transients.
Reanalysis (Section 3.1.4.1) of the steamline break core response transient is required to address the increase in safety injection delay time of 4 seconds. The steamline break core response transient used in the DNBR evaluation is sensitive to the time that safety injection water reaches the RCS.
Reanalysis of the locked rotor/shaft break event is required to address the unavailability of the RCS Low Flow reactor trip function assuming a single active failure of the low flow channel located in the loop with the affected reactor coolant pump. This analysis will also be affected by the 20% tube plugging and will be provided at a later date.
3.14.1 Steamline Break Core Response The current safety analysis for steamline break core response is presented in Reference 1. The analysis assumed a Thermal Design Flow of 195000 gpm to bound SONGS 1 operation with 15% or 20% steam generator tube plugging level.
The analysis is performed at Hot Zero Power conditions, which are
.the same'for either Nominal Tavg Program operation or Reduced Tavg Program operation. As such, the analysis would is applicable for SONGS 1 operation on the Reduced Tavg Program with 20% tube plugging. However, reanalysis of the steamline break core response transient is required to address the increase in safety injection delay time of 4 seconds. The steamline break core response transient used in the DNBR evaluation is sensitive to the time-that safety-injection water reaches the RCS. The analysis assumed a safety injection delay time of 22 seconds from the time that the low pressurizer pressure SI setpoint is reached until the safety injection pumps reach full speed. The analysis also assumed one train of SI injecting into one line of the RCS with a safety injection line boron concentration of 1500 ppm.
For the credible break case at Hot Zero Power conditions (Case 4.1 of Reference 1), the RCS pressure does not go below the shutoff head of the
.safety injection pumps until 61 seconds after the low pressurizer pressure SI setpoint is reached. As such, the increased safety injection delay time of 26 seconds from 22 seconds does not impact the credible break case since safety injection flow does not start for 61 seconds after the setpoint is reached. Thus, the credible break analysis remains valid for the increase of 4 seconds in the safety injection delay time.
For the hypothetical break cases at Hot Zero Power conditions (Cases 3.1, 3.2, 3.3 of Reference 1), the RCS pressure is below the shutoff head of the safety injection pumps by the end of the assumed 22 second delay. The borated water of the safety injection flow is the main contributor to the magnitude of the core heat flux transient. The borated water supplies negative reactivity to limit the peak return to power associated with the steamline break event. This peak return to power is a critical parameter "in the DNBR evaluation. Any additional delay in the safety injection flow would result in a higher peak return to power. As such, reanalysis of the
-hypothetical break cases is required for the steamline break transient.
A hypothetical steamline break is defined as the double ended rupture of a main steamline. This event is classified as an ANS Condition IV event, a limiting fault. Condition IV occurrences are faults which are not expected to take place, but are postulated because their consequences would include the potential for the release of significant amounts of radioactive material. They are the most drastic which must be designed against and represent limiting design cases. Condition IV faults are not to cause a fission product release to the environment resulting in an undue risk to the public health and safety in excess of guideline values of 10 CFR 100. A single Condition IV fault is not to cause a consequential loss of required functions of systems needed to cope with the fault including those of the Emergency Core Cooling System and Containment.
The purpose of this analysis is to show that the acceptance criteria stated above are met for the hypothetical break cases (Case 3.1, 3.2, and 3.3 of Reference 1) analyzed with the increase in safety injection delay time of 4 seconds to a total delay time of 26 seconds from the time of low pressurizer pressure SI setpoint is reached until the safety injection
.pumps reach full speed. The acceptance criteria for hypothetical breaks is demonstrated by showing that no DNB occurs. This ensures that there is no damage to the fuel cladding and no release of fission products from the fuel to the RCS.
The cases reanalyzed are:
3.1 Hypothetical break outside the flow restrictor. SIS configuration:
1 train injecting through 1 line.
3.2 Hypothetical break inside the flow restrictor. SIS configuration: 1 train injecting through 1 line into an intact loop.*
3.3 Hypothetical break inside the flow restrictor. SIS configuration: 1 train injecting through 1 line into the faulted loop.*
The faulted loop is defined as the loop in which the steamline ruptures. The other two loops are referred to as the intact loops.
Transient Description The steam releases arising from a rupture of a main steamline or from the
"'inadvertent opening of a steam dump valve would result in an initial increase in steam flow from all three steam generators which decreases during the transient as steam pressure decreases. The increase in energy removal from the RCS causes a reduction of coolant temperature. In the presence of a negative moderator temperature coefficient, the cooldown results in an insertion of positive reactivity which may cause a return to power. The decrease in reactor coolant temperature also causes the water in the RCS to shrink which reduces pressurizer level and pressure. The shrink in the RCS inventory may be severe enough to cause the pressurizer to empty and the fluid in the upper head of the reactor vessel to saturate.
In the event that the reactor is at power, a reactor trip would be generated manually or by the reactor protection system from one of the following signals.
- 1. High nuclear flux 2."Steam and feedwater flow mismatch
- 3. Safety injection initiation Following the reactor trip or if the transient is initiated from zero power, there is a possibility that the core will return to power due to the positive reactivity insertion. The return to power is limited by
.Doppler reactivity feedback and the introduction of borated water from the safety injection system. The core is ultimately shutdown by borated water from the safety injection system and/or from the chemical and volume control system.
Safety injection may be actuated during the transient manually or by a signal generated from low pressurizer pressure or high containment pressure.
Feedwater, which enhances the RCS cooldown, would be isolated manually or by safety injection initiation.
Analysis Methodology The analysis of the steamline rupture has been performed to determine:.
- 1.
The core heat flux and RCS temperature and pressure-resulting from the cooldown following the steamline rupture. The LOFTRAN code (Reference 2) was used.
- 2.
The thermal and hydraulic behavior of the core following a steamline rupture. A detailed thermal and hydraulic digital-computer code, THINC, was used to determine if DNB occurs for the conditions computed in item 1.
Assumptions Studies have been performed to determine the sensitivity of steamline break analysis results to various input assumptions (Reference 3).
Based on this study, the following assumptions are used for the analysis of the main steamline rupture for SONGS 1.
- 1.
Initial conditions - The plant is assumed to be operating at hot zero power with RCS pressure equal to nominal RCS pressure (2100 psia), RCS flow rate equal to nominal RCS Thermal Design Flow (195000 gpm), RCS temperature equal to no load Tavg (535 OF) and steam generator pressure equal to the no load pressure.
Initial pressurizer water volume is assumed to be 345 ft3.
This corresponds to a pressurizer level of approximately 20%.
(While the actual plant pressurizer operating level is 25% at HZP, the impact on the results of the analysis is negligible.)
Initial Core boron concentration is assumed to be 0 ppm.
- 2.
Offsite power - Offsite power is assumed to be available throughout the transient. This results in reactor coolant pump
"(RCP)"operation throughout the transient. Actually, for SONGS 1 the RCPs will trip as a result of the SI signal even with offsite power available. This enhances the heat transfer between the RCS and the secondary causing a more severe cooldown and return to power. This assumption is shown to be conservative in Reference 3 and in the past SONGS 1 licensing basis steamline break analysis.
- 3.
Shutdown margin - the initial shutdown margin assumed for the analysis is calculated assuming no load, end of life (EOL),
equilibrium xenon conditions and the most reactive RCCA stuck in its fully withdrawn position. A value of 1.9% Dk/k is assumed.
This is the SONGS 1 EOL shutdown margin requirement.
- 4.
Reactivity coefficients - A negative moderator coefficient is assumed corresponding to the end of life rodded core with the most reactive RCCA in its fully withdrawn position. The keff versus temperature at 1000 psia corresponding to the negative moderator temperature coefficient used is shown in figure 0.1.
The effect of power generation in the core on overall reactivity is shown in figure 0.2.
For hypothetical breaks inside the flow restrictor, the core properties associated with the sector nearest the faulted steam generator and those associated with the remaining sectors were conservatively combined to obtain average core properties for reactivity feedback calculations. Further, it was conservatively assumed for all of the breaks (credible and hypothetical inside and outside of the flow restrictor) that the core power distribution was uniform. These two conditions cause underprediction of the Doppler reactivity feedback in the high power region near the stuck rod..
To verify the conservatism of this method, the reactivity as well as the power distribution was checked for the limiting statepoints of the cases analyzed. This core analysis considered the Doppler reactivity from the high fuel temperature near the stuck RCCA, moderator feedback from the high water enthalpy near the stuck RCCA, power redistribution and nonuniform core inlet temperature effects in the case of the hypothetical breaks inside the flow restrictor. For cases in which steam generation occurs in the
.high flux regions of the core, the effect of void formation was also included. It was determined that the reactivity employed in the kinetics analysis was always larger than the reactivity calculated including the above local effects for the statepoints.
These results verify conservatism; i.e., underprediction of negative reactivity feedback from power generation.
- 5.
Feedwater - For hypothetical breaks nominal feedwater flow is assumed at the transient initiation and continues until 26 seconds after the safety injection setpoint is reached. The 26 second delay is a conservatively long time for signal processing, valve realignment, etc. The temperature of the feedwater is assumed to
- be 72*F.
- 6.
Auxiliary Feedwater - Auxiliary feedwater flow is assumed to start at the transient initiation and continue throughout the transient. A flow rate of 1419 gpm (10% of nominal feedwater flow) is assumed. Flow is divided equally between all three steam generators. The temperature of the auxiliary feedwater is assumed to be 320F,.
- 7.
Safety Injection - Safety injection flow is assumed to start 26 seconds after the low pressurizer pressure SI setpoint is reached. The low pressurizer pressure setpoint assumed in the analysis is 1680 psia. This represents a nominal setpoint of 1750 psia minus uncertainties, instrument errors, etc.
The 26 second delay is a conservatively long time for signal processing, valve realignment, etc.
Flow rates are calculated based on the operation of only one train of safety injection. The failure of the other train is the worst active single failure assumption. Flow rates are calculated based on injection into the RCS via one line. The SI flow rates vs. RCS pressure used in the analysis are shown in figure 0.3.
The temperature of the safety injection water is assumed to be 328F.
- 8.
Decay Heat -
No credit is taken for decay heat since this would inhibit the cooldown of the RCS.
- 9.
Metal Heat - No credit is taken for heat transfer from the thick metal throughout the RCS to the coolant.
- 10.
Accident Simulation - In computing the steam flow during a steamline break or the inadvertent opening of a steam dump valve, the Moody Curve (Reference 4) for f(L/D) = 0 is used.
The break area assumed for hypothetical breaks outside the flow restrictor is 1.12 ft2 per loop. This is the area of the steamline flow restrictor. All three steam generators are assumed to blow down to atmospheric pressure through their respective flow.
restrictors.
The break areas assumed for hypothetical breaks inside the flow restrictor are 1.842 ft2 for the faulted loop and 0.56 ft2 for the intact loops.
1.842 ft2 is the area of the main steamline and 0.56 ft2 is one half the area of the steamline flow restrictor. The faulted steam generator is assumed to blow down to atmospheric pressure through the ruptured steamline and the intact steam generators are assumed to blow down through the flow restrictor'in'the faulted loop.
- 11.
Steam Generator Water Entrainment - Perfect moisture separation in the steam generators is assumed. This assumption leads to conservative results, especially for large breaks, since there would be considerable entrainment of the water in the steam generators following a steamline break. Entrainment of water would reduce the magnitude of the cooldown of the RCS.
Results The results of the Case 3 LOFTRAN runs are shown in Figures 3.1.1 - 3.3.12. The calculated sequences of events for the Case 3 LOFTRAN runs are listed in Tables 3.1 -
3.3.
The analysis of the thermal and hydraulic behavior of the core following the steamline break for the above cases determined that no DNB occurs for any of the cases.
Conclusions The results of the analysis show that the DNBR remained above the limit value for all of the cases analyzed. This ensures that DNB will not occur following the hypothetical cases analyzed. (As shown in Reference 1, the credible break case does not result in a DNBR below the limit value.)
Therefore, no releases of fission products from the fuel will result from a hypothetical break with a total safety injection delay time of 26 seconds from the time the low pressurizer pressure SI setpoint is reached until the safety injection pumps reach full speed.
3.1.4.1.1 References "Southern California Edison (SCE) San Onofre Unit 1 Steamline Break Analysis," SCE-88-712, Letter from L. E. Elder (W) to 3. T.
Reilly (SCE), July 15, 1988.
- 2.
Burnett, T. W. T., et al., "LOFTRAN Code Description",
WCAP-7907-A, April 1984.
- 3.
Hollingsworth, S. D. and Wood, D. C., "Reactor Core Response To Excessive Secondary Steam Releases", WCAP-9227, January 1978.
- 4.
Moody, F. S., "Transactions of the ASME, Journal of Heat Transfer", Figure 3, page 134, February 1965.
TABLE 3.1 TIME SEQUENCE OF EVENTS CASE 3.1 Hypothetical Break Outside The Flow Restrictor SIS Configuration: 1 train injecting through 1 line Event Time, sec Steam line ruptures outside the
- 0.
flow restrictor (double ended)
AFW flow to all 3 Steam
- 0.
Generators starts Low pressurizer pressure SI setpoint
- 17.
is reached Pressurizer empties
- 18.
Shutdown margin is lost
- 21.
(reactor is critical)
Fluid in the upper head saturates
- 24.
Main Feedwater flow to all three
- 43.
Steam Generators stops SI flow to the RCS starts
- 43.
Borated SI water reaches the core
- 44.
Pressurizer starts to refill
- 46.
Peak power level (64% of nominal)
- 62.
is reached TABLE 3.2 TIME SEQUENCE OF EVENTS CASE 3.2 Hypothetical Break Inside The Flow Restrictor SIS Configuration: 1 train injecting through 1 line into an intact loop
- Event Time, sec Steam line ruptures inside the
- 0.
flow restrictor (double ended)
AFW flow to all 3 Steam
- 0.
Generators starts Low pressurizer pressure SI setpoint
- 19.
is reached Pressurizer empties
- 20.
Shutdown margin is lost
- 21.
(reactor is critical)
Fluid in the upper head saturates
- 26.
Main Feedwater flow to all three
- 45.
Steam Generators stops SI flow to the RCS starts
- 45.
Borated SI water reaches the core
- 46.
Pressurizer starts to refill
- 48.
Peak power level (60% of nominal)
- 58.
is reached The faulted loop is defined as the loop in which the steamline ruptures.
The other two loops are referred to as intact loops.
TABLE 3.3 TIME SEQUENCE OF EVENTS CASE 3.3 Hypothetical Break Inside The Flow Restrictor SIS Configuration: 1 train injecting through 1 line into the faulted loop
- Event Time, sec Steam line ruptures inside the
- 0.
flow restrictor (double ended)
AFW flow to all 3 Steam
- 0.
Generators starts Low pressurizer pressure SI setpoint
- 19.
is reached Pressurizer empties
- 20.
Shutdown margin is lost
- 21.
(reactor is critical)
Fluid in the upper head saturates
- 26.
Main Feedwater flow to all three
- 45.
Steam Generators stops SI flow to the RCS starts
- 45.
Borated SI water reaches the core
- 46.
Pressurizer starts to refill
- 48.
Peak power level (57% of nominal)
- 56.
is reached The faulted loop is defined as the loop in which the steamline ruptures. The other two loops are referred to as intact loops.
K 142 e
f f
14--
K
.0 1099' Zero Power, 1000 psia End of Life Core, Stuck Rod 2
240 2
320 0
4 440 520 Core Average Temperature (OF)
Figure 0.1 keff vs Temperature 26
I 1.5' t
1.4 g
1.3 1____
r a
12 o
o 1.1 f
P o
0.9 w
e
- 0.
r g aCt 0.5 0
t 0.2 0.5 f
9 c
0 I
n P 0.1 c
0 20 40 Power (% of nominal)
Figure 0.2 Doppler Power Defect vs Reactor Power 27
10 -
a 9
I Train 2 Lines Injecting 7
F, 11 wg 4-1 Line Injecting 0
02 0.4 0.5 0.8 1
12 Pressure (psia)
Figure 0.3 Safety Injection Flow vs RCS Pressure
-28
e
- 0. ).7
.4 L.
z.1
- 0.
- 0.
- 20.
- 40.
- 60.
S0.
100.
120.
140.
160.
TIME (SEC)
Figure 3.1.1 Nuclear Power 0 z.7 b.5 0
0.1
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.1.2 Core Heat Flux
.29
2500.
- a. 2000.
Li S1500.
En at n-1000.
SO. 50.
20 40 6o
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.1.3 RCS Pressure
-- 600.
c 500.
SOO 400.
La cc 500.
La 0
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME ISEC)
Figure 3.1.4 Core Average Temperature 730
PRZR WATER VOL ECU rti R V INLET TEMP IDEG ri ED tp) t9 ca IS C)
ED u~
EDi Oa 40 fa C
tt2 ECD IDD 0
-3 t
EU9 N
CD
12 LJ.
C9 0
5.
- 0.
100.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.1.7 Core Flow 3000.
z2000.
~.1000.
- 0.
c W -1000.
-2000.
30.0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.1.8 Reactivity
i 1.75 z
1.5 o
U 1.25 ac 0.7S a
.5 a
o
.25
- e.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.1.9 Feedwater Flow 500.
400.
z 300.
0 a
200.
L..
- 100.
U
- 0.
- 20.
- 40.
S0.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.1.10 Core Boron
- 33
STEAM PRESSURE IPSIA)
STEAM rLOV (rRAC or. NOH) lu tnUs Ia(a, C
=CD tab 9
toD
CORE HT rLX irRC Or NOMI NUC POWER IFRAc OF NOMI
.n a) e I~
IN tfl
- 0) t CM U1
)C9 e~~~~C e
a s*D ou t9 t
CORE AVE TEMP IDEG ri RCS PRESSURE IPSIA) ou m
(n C
lu P
Puu CC
- to
- o CA cp
,IC 0'
D ODD
600.
o 500.
CL 400.
LiJ 300.
z m 200.
100.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.2.5 Reactor Vessel Inlet Temperatures 400.
5 00.
-9 w 200.
cc
- 00.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.2.6 Pressurizer Water Volume 37
12 C)
.4 0
L) 2
- 0.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.2.7 Core Flow 0000.
2000.
.1000.
-2000.
-5000.
- 0.
- 20.
- 40.
- 60.
- 80.
100. 120.
140.
160.
TIME (SECi Figure 3.2.8 Reactivity 38
S a 1.75 0
z Ua 1.2S 1.5 o
a.25 cc
.7 a
.5 L..25
- 0.
- 0.
- 20.
- 40.
- 60.
SO.
100.
120.
140.
160.
TIME (SEC)
Figure 3.2.9 Feedwater Flow SOO 500.
z c 500.
200.
0 200.
- 0.
100.
0..
- 0.
- 20.
- 49.
- 60.
- 0.
100.
120.
140.
160.
TIME (SECI Figure 3.2.10 Core Boron 39
-1000.
cn 800.
Li 600.
ac 400.
30 z 6 U0 200.
- 0.
- 0.
- 20.
- 40.
SO.
BO.
100.
120.
140.
160.
TIME (SEC)
Figure 3.2.11 Steam Pressure x76.
0 5 Li.
- 4.
- 95.
- 0.
- 20.
- 40.
- 6.
- 80.
100.
120.
140. 160.
TIME (SEC)
Figure 3.2.12 Steam Flow
- 40
CORE HT FLX IFRC OF NOHI NUC POWER irRAC Or NOII
- ~
~
~
b
- n S S
bJ (N
b (f
- 0)
(N cfl 0)in
.4
_5__
tlOD 3c4
.d.
S
-CD tto
2500.
2000.
1500.
C, Li 01000.
500.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.3.3 RCS Pressure 600.
500.
0 ii 400.
a 500.
u 200.
100.
- 0.
- 20.
- 40.
- 60.
- 90.
100.
120.
140.
160.
TIME (SEC)
Figure 3.3.4 Core Average Temperature 42
600.
500.
400.
z 200.
100.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC Figure 3.3.5 Reactor Vessel Inlet Temperatures 400.
500.
N 100.
- 0.
- 20.
- 48.
- 68.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.3.6 Pressurizer Wfater Volume
-43
i1.4 1.2 0
.6 L.4 LJ
- 0.
- 0.
- 20.
- 40.
- 60.
SO.
100.
120.
140.
160.
TIME (SEC)
Figure 3.3.7 Core Flow 3000.
z 2000.
1800 0..
LJ
& -1000.
-2000.
-3000.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME ISECI Figure 3.3.8 Reactivity
,44
1.75 1.25 a
- 1.
S.75 or
.5
.25
- 0.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.3.9 Feedwater Flow 500.
C. 400.
z o 300.
0 200.
0 100.
- 0.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.3.10 Core Boron 45
1000.
800.
LJ CL 600.
400.
Li 200.
- 0.
- 0.
- 20.
- 40.
- 60.
- 80.
100.
120.
140.
160.
TIME (SEC)
Figure 3.3.11 Steam Pressure T7.
z
- 6.
u 5.
- 4.
z 2.
- 0.
- 20.
- 40.
- 68.
- 80.
100.
120.
140.
160.
TIME ISEC)
Figure 3.3.12 Steam Flow 46
3.1.4.2 Locked Rotor/Shaft Break (To be provided later) 3.1.5 Conclusions of the Non-LOCA Safety Evaluation The non-LOCA safety evaluation supports SONGS 1 operation with the Reduced
'Tavg Program with up to 20% tube plugging level in any steam generator, except for the locked rotor/shaft break event which will be provided later. Also, supported in this safety evaluation is the increase in safety injection delay time of 4 seconds. The hypothetical break cases of the steamline break core response transient were reanalyzed to support the increase in safety injection delay time.
3.3 STEAM GENERATOR TUBE RUPTURE The analysis in the SONGS 1 UFSAR was performed by the NRC during the SEP review. Accordingly, Westinghouse cannot perform a quantitative evaluation regarding the impact of a steam generator tube plugging level of up to 20% on an SGTR event. A qualitative evaluation is provided below based on Westinghouse experience with increases in steam generator tube plugging for other PWRs.
With respect to a steam generator tube rupture (SGTR) event, steam generator tube plugging levels of up to 20% will result in changes to the primary and/or secondary operating conditions in order to maintain full power output. For SONGS 1, the secondary pressure (and corresponding steam temperature) are decreased to compensate for this reduction in available steam generator heat transfer area. This change to secondary operating conditions will impact the thermal-hydraulic results of an SGTR event. Consequently, the offsite doses calculated for an SGTR event would be expected to be impacted, as well.
For an SGTR event, the thermal-hydraulic mass releases of primary-to secondary'break flow-and atmospheric steam release via the ruptured steam generator are the controlling factors for the offsite radiological consequences. The reduction in operating secondary pressure will increase the primary-to-secndary pressure differential prior to reactor trip thereby increasing the primary-to-secondary break flow. Conversely, the reduced secondary pressure results in less energy to be dissipated, and therefore less atmospheric steam will be released via the ruptured steam generator. Previous experience with similar increased tube plugging scenarios indicates that the results of the increased primary-to-secondary break flow and decreased atmospheric steam release via the ruptured steam generator are such that only a minimal increase in the offsite doses would be expected. Although the basis for the SONGS 1 SGTR offsite doses reported in the UFSAR was not provided by Westinghouse, it is expected that the effect of a tube plugging level of up to 20% would not increase the SGTR offsite doses reported in the SONGS 1 UFSAR above the 10 CFR 100 regulatory limits.
4.0 CONCLUSION
The San Onofre Unit 1 UFSAR Chapter 15 Accident Analyses excluding LOCA and locked rotor/shaft break events (which will be provided later) have been evaluated with respect to operation of the plant under the following conditions:
Maximum steam generator tube plugging level of 20% in any steam generator Delay in safety injection delivery of 26 seconds from initiation of safety injection signal Reactor coolant vessel average temperature of 551.5 0F Unavailability of the low flow reactor trip for Reactor Coolant Pump locked rotor/shaft break protection Based on the analyses and evaluations in this report, San Onofre 1-Uif1'.canhbe"operated under the above conditions without violating any of the related UFSAR Chapter 15 safety analysis limits.