ML20198F341
| ML20198F341 | |
| Person / Time | |
|---|---|
| Site: | Callaway  |
| Issue date: | 08/08/1997 |
| From: | UNION ELECTRIC CO. |
| To: | |
| Shared Package | |
| ML20198F337 | List: |
| References | |
| FACA, NUDOCS 9708130017 | |
| Download: ML20198F341 (5) | |
Text
.___ __-_-_ _ _ - _ - _ -
6 ULNRC-03627 -
ATTACHMENT 1 TECHNICAL SPECIFICATION CHANGES Current Table 2.2-1 (Page 2-4)
Current Table 3.7-2 (Page 3/4 7-3) - ,
ITS Table 3.7.1-2 (Page 3.7-4)_
ITS Bases Page B 3.7-4
. ,. 1 I
4
, a v l
TABLE 2.2-1 h REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS 9
k TOTAL SENSOR ERROR FUNCTIONAL UNIT ALLOWANCE (TA) Z 151 TRIP SETPOINT ALLOWABLE VALUE E 1. Manual Reactor Trip N.A. N.A. N.A. N.A. N. A.
U 2. Power' Range, Neutron Flux
~
- a. High Setpoint 7.5 4.56 0 s109% of RTP* 5112.3% of RTP*
- b. Low Setpoint 8.3 4.56 0 s25% of RTP* $28.3% of RTP*
- 3. Power Range, Neutron Flux, 2.4 0.5 0 $4% of RTP* $6.3% of RTP*
High Positive Rate with a time with a time constant 22 constant 22 seconds seconds
- 4. Deleted
';* 5. Intermediate Range, 17.0 8.41' O $25% of RTP* $35.3% of RTP*
Neutron Flux
- 6. Source Range, Neutron Flux il7.0 10.01' O $10' cps $1.6 x 10' cps
- 7. Overtemperature AT i9.3 6.47 1.83 See Note 1 See Note 2
! +1.24***
- 8. Overpower AT 5.0 1.90 1.65 See Note 3 See Note 4 l
- 9. Pressurizer Pressure-Low 5.0 2.21 2.0 21885 psig 21874 psig
- 10. Pressurizer Pressure-High . $2335 psig s'""^ psig
.2 11. Pressurizer Water Level- .0 2.18 2.0 592% of 93.8% of instrument span instrument span 2h High 2.5 1.38 0.6 290% of loop 88.8% of loop
[ 12. Reactor Coolant flow-Low minier.um minimum 2 7 fjg J,0 measured flow ** measured flow **
A zsgs x
- g RTP = RATED THERMAL POWER
'g
- Minimum Measured Flow - 95,660 gpm
- Two Allowances (temperature and pressure, respectively)
l l'
MEV; 0
,, TABLE 3.7-5 SIEAM LINE SAFETY VALVCS PER LOOP I }
VALVE NUMBER LIFT SETTING
- ti"- ORIFICE $1ZE Loop 1 Loop 2 Loop 3 1,000 4
^
YO55 V065 V075 .V045 1185 psig ,
16.0 sq. in.
V056 V066 V076 V046 1197 psig 16.0 sq. in. ,
V057 V067 V077 V047 .1210 psig 16.0 sq.-in.
, V058 V068 V078 V048 1222 psig 16.0 sq. in.
V059 V069 V079 .V049 ' 1234 psig 16.0 sq. in.
/'
( ,
- The lift setting pressure shall correspond to ambient conditions of the valve at nominal operating temperature and pressure Ne s t- [p j /;,Q .csdnf bkrdMM ir IY #
Me noinina/ .r.ef / sin f. A a rdh AA *#"1
/o besax is.?/ll sf Mr n o m i u l .rs Q s W CALLAWAY - UNIT 1 3/4 7-3 '
. . _ . . _ _ . . . . . . . _____U
i HSSVs -
3.7.1 Table 3,7.12 (page 1 of 1)
Main Steam Safety Valve *.ift Settings LIFT SETTING VALVE NLABER (psig +-tt)
+s/-l%
- 1 #2 #3 #
ABV0055 ABV0065 ABV0075 ABV0045 1185 ABV0056 ABV0066 ABV0076 ABV0046 1197 ABV0057 ABV0067 ABV0077 ABV0047 1210 ABV0068 ABV0078 ABV0048 1,222 ABV0058 ABV0059 ABV0069 ABV0079 ABV0049 1234
) ,
I CALLAWAY PLANT ITS 3.7 4 5/15/97.
MSSVs B 3.7.1 g
BASES ACTIONS- B.1 and B.2 (continued)
If THERMAL POWER or the Power Range Neutron Flux High trip setpoints is not reduced within the associated Completion Time, or if one or more steam generators have less than two HSSVs OPERABLE, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit mest be placed in at least H00E 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in H00E 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
SURVEILLANCE SR 3.7.1.1 REQUIREMENTS i This SR verifies the OPERABILITY of the MSSVs by the verification of each MSSV lift setpoint in accordance with the Inservice Testing Program (Ref 5). ,g i
The ASME Code specifies the activities and frequenc snec(ssary to satisfy the requirements. Table 3.7.1 2 allows a +-it->
setpoint tolerance for OPERABILITY. The lift settings, acc rding to Table 3.7,1^2. correspond to ambient conditions of the valve at nominal operating temperature and pressure.
This SR is modified by a Note that allows entry into and operation in H00E 3 prior to perfoming the SR. The MSSys may be either bench tested or tested in situ at hot conditions using an assist device to simulate lift pressure. If the MSSVs are not tested at hot conditions, the lift setting pressure shall be corrected, if necessary, to ambient conditions of the valve at operating temperature and pressure.
REFERENCES 1. FSAR, Section 10.3.2, Main Steam Supply System System Description.
- 2. ASME, Boiler and Pressure Vessel Code,Section III, Artir.le NC 7000, Class 2 Components.
- 3. FSAR. Section 15.2, Decrease in Heat Removal by the l Secondary System. l 3
(continued)
CALLAWAY PLANT ITS BASES B 3.7 4 5/15/97
h ULNRC-03627 ATTAC11 MENT 2 SIGNIFICANT HAZARDS EVALUATION
ULNRC-03627 Attachment 2 Page 1 of 9-SIGNIFICANT-HAZARDS EVALUATION
- i This" amendment application requests a revision to Technical I Specification (TS) 3.7.1.1_(Table 3.7-2) and 2.2 (Table 2.2-1) '
These_ specifications-are revised to increase the lift setting tolerance for the main steam safety valves from i1% to +3/-1%.
Background
The function of the main steam line safety valves is to provide
-overpressure protection, ensuring that the secondary system pressure will be limited to within 110% of its design pressure (1185 psig) during the most severe anticipated system operational
-transient. The total relieving capacity for all valves on all steam lines is 113% of the total secondary steam flow.
The existing tolerance of i1% specified in Technical
-Specification 3/4.7.1 for steam line safety valve lift settings
-is based on the design requirements for safety valves specified in ASME Section III, Subsection NC-7614.2. The 11% tolerance is appropriate for design criteria, but 1s not appropriate for-testing acceptance criteria for the following reasons: a) The 11% lift setting tolerance currently specified does not take into consideration the service conditions of the safety valves _ For safety valves subjected to a constant load for extended periods fof__ time without being' cycled, it is common for the valve springs to take a set resulting in a slight increase in the spring rate, until broken loose during the initial test stroke of1the valve.
ASME Section XI test criteria requires the performance of 3
-successive lifts with no adjustments to the valve lift setting.
Due to the_ valve spring taking a set as described above, the first-test-lift is commonly found to be slightly out of tolerance and the~second and third lifts within tolerance, b) ASME Section XI, Subsection IWV-3512 requires safety valves to be tested using OM-1. Q4-1 requires that the testing methodology utilized to test safety valves be accurate-to +2/-1%. The +3/-1%
tolerance specified by this TS change does not include the testing accuracy.
The.ASME Section XI schedule-used previously for testing valves
-wi-ll continue to be used, however, all valves that are tested and found outside the i1% band will be reset to within i1%.
Industry operating experience has also demonstrated that a setpoint tolerance for the main steam safety valves of only i1%
results in safety valves frequently failing surveillance tests.
Information Notice 86-56, " Reliability of Main Steam Safety
ULNRC-03627 Attachment 2 Page 2 of 9 Valves," tabulated a number of problems with setpoint drift as reported in various LERs. This information notice discussed the various safety concerns that may be encountered with setpoint drift. Union Electric has considered these concerns in the proposed relaxed tolerance limits. Other plants, such as, Diablo Canyon, and Wolf Creek have been granted setpoint tolerance relaxations.
The proposed tolerance relaxation meets overpressure protection l requirements and all ASME code requirements. This is discussed later in this evaluation. In addition, evaluation of the FSAR accident analyses affected by the change has demonstrated that the conclusions for these analyses as stated in the FSAR remain valid, and results in no additional operational concerns.
All safety analyses done to support the MSSV tolerance change were performed using WCAP-12910 Rev.1-A " Primary Safety Valve Surge Line Loop Clearance Models." Specifically, primary safety valves utilize a TS setpoint of 2500 psia, a i1% tolerance and
+1% setpoint shift. Union Electric calculated a loop seal purge time of 1.15 seconds (using the methodology of WCAP-12910) which was implemented in the analysis as a time delay. i
{
Non-LOCA Accident Evaluation l l
l Many of the non-LOCA accidents are not affected by the assumption I of maximum tolerance on the main steam line safety valves. This is because the pressures reached in the transient never approach the values for the lift setpoints. The pressure in a given transient would have to reach 2500 psia on the primary side or 1236 psia on the secondary side for the transient to begin to be l
affected by the increased tolerance, where the 1236 psia j secondary setpoint reflects the Westinghouse transient l methodology of modeling all main steam line safety valves as l lifting at the same setpoint. All FSAR Chapter 15 non-LOCA l transients have been evaluated and most are not significantly affected by the main steam line safety valve increased setpoint tolerance. The following accidents could possibly be impacted ,
either because of Departure from Nucleate Boiling Ratio (DNBR) {
concerns or other licensing-basis acceptance criteria: '
Loss of External Load / Turbine Trip Westinghouse used LOFTRAN to reanalyze the loss of external load / turbine trip to assure the DNB design limits were not exceeded. In addition to modeling +3/-1% MSSV tolerances, changes were made to the model to account for the presence of a pressurizer loop seal and to expressly model five MSSVs per steam generator. The results of this revised DNBR analysis are
I ULNRC-03627 f Attachment 2 Page 3 of 9 contained in Appendix A. This analysis showed that the DNB design limits were not exceeded.
A sensitivity study was performed, to assess the effect on DNBR, in which the pressurizer safety valves were modeled as opening at 2425 psia (-3% tolerance) and the loop seal clearing time was neglected. This modeling results in minimum pressurizer pressure, which is conservative for DNBR evaluations. The Westinghouse DNBR evaluation of this sensitivity shows negligible impact on DNBR, Wed.inghouse reanalyzed the loss of external load / turbine trip to assure design pressure was not exceeded (see Appendix B). This analysis shows that the design pressure was not ?xceeded with an expanded main steam line safety valve setpoint tolerance band, provided that the high pressurizer pressure safety analysis trip setpoint was reduced to 2425 psia.
- Rod Withdrawal at Power The Westinghouse review of the rod withdrawal at power shows that the minimum reported DNBR occurs before MSSV actuation for most analyzed cases. Note that this transient is not very sensitive to secondary side changes, and the FSAR analyses conclusions remain valid,
- RCP locked rotor / shaft break Westinghouse reviewed the locked rotor / shaft break accident and it was found that the MSSV - 1erance increase to +3/-1% has no impact on the transient.
- Loss of Normal Feedwater/ Station Blackout Feedwater Line Break Partial Loss of Forced Reactor Coolant Flow Complete Loss of Forced Reactor Coolant Flow Westinghouse determined that the DNBR transient is not changed significantly for the relaxation in setpoint tolerance and the conclusions reached for the DNBR accidents in the FSAR analyses remain valid.
- Inadvertent ECCS Actuation at Power Westinghouse determined that the inadvertent ECCS actuation at power event would not be impacted by an increased MSSV tolerance.
The event only relies on a small fraction of the capacity of a
ULNRC-03627' Attachment 2 Page 4 of 9 single MSSV and_-the current analysis conservatively models +3%
tolerance.
Non-DNB Transients-Westinghouse determined that the locked rotor and rod ejection-events will not be affected by the setpoint tolerance as it-relates to the peak heat flux calculation. These analyses-assume a conservative pressure which is less than theJsteady state RCS pressure. This pressure is maintained at a constant value throughout the transient so as to maximize the peak heat flux.
Therefore,-the TSAR analyses conclusions remain valid.
Westinghouse and Union Electric reviewed the quantity of steam mass released from the-main steam line safety valves and +
determined that doses will not be significantly affected by the revised tolerance values. The primary effect of the increase in the safety valve tolerance on the impacted accidents is to alter the time at which the valves would open during the pressure increase transient. Even though the initial steam flow through the safety valves will increase due to a higher: back pressure, the integrated. mass release relieved from the1 secondary side is not expected to be significantly increased. ,
' Westinghouse reviewed the effect of the setpoint tolerance change on long-term heat removal for both the loss of normal feedwater- ,
and station blackout events. The competing effects of increased / decreased heat removal capability on the secondary side and higher / lower average coolant temperatures on the-primary side result in no significant impact on-the heat removal' capability of the secondary system. There is significant margin in these events to filling the pressurizer and the conclusions presented in the FSAR analyses remain valid.
Union Electric reviewed the applicable AFW calculations and
-determined that the potentially higher discharge pressure against which the AFW must flow due to the increase in the MSSV tolerance will have no affect on Auxiliary Feedwater flow. The AFW flow calculations assumed steam generator pressure-was 1236-psia (3%
--tolerance on lowest safety valve set pressure).
Union Electric revised the ANSI /ASME piping system analysis
-equations to assure elements pertaining to internal pressure were 1 accounted for. This pressure stress is. typically small with l respect to the moments generated due to occasional and sustained loads. The-additional 36 psi related to the +2% increase in MSSV set pressure will have no appreciable affect on secondary side pipe stresses.
Attachment 2 L Page 5 of 9 LOCA Accident Evaluation A safety evaluation for a safety valve setpoint tolerance relaxation to +3/-l% on the Chapter 15 FSAR LOCA accidents was performed in order to justify relaxation of the current +1%
tolerance on the main steam line safety valves.
The current large break LOCA analysis forming the licensing basis for_Callaway Plant (break size greater than or equal to 1.0 sq.
ft.) results in a very rapid (approximately 30 seconds) depressurization of the RCS from the operating pressure to a pressure slightly above that of the containment. Because of the rapid primary depressurization, the secondary side of the steam generators quickly becomes a heat source rather than a heat sink such that the main steam safety valves are not challenged. The pressurizer safety valves are also not challenged because of the RCS depressurization. Therefore, the proposed safety valve tolerance relaxation will have no effect on the large break LOCA analysis.
The current small break LOCA analysis forming the licensing basis for Callaway Plant causes the system to depressurize to a pressure slightly above that of the steam generator secondary side pressure relief. The main steam safety valves provide a significant path for RCS energy release until steam venting through the break occurs. The primary pressure and the duration of time that the RCS primary remains above the secondary side pressure is governed by the rate of decay energy removal through i the break and the amount of heat transferred to the steam generator secondary side. A slight increase in RCS pressure is computed to occur during this portion of the transient due to the higher secondary pressure as a result of the relaxed tolerances.
Analysis has shown that increasing the secondary pressure, and as a result, the RCS pressure, results in higher peak cladding temperatures (PCT). The PCT increase is 120 F, which when added to existing penalties, results in a total penalty of 1626'F. The current Callaway small break analysis assumes nominal main steam line safety valve setpoints. An evaluation of the relaxed tolerance on PCT shows there is still a significant margin to the 2200*F regulatory limit. Further, since the small break LOCA is a depressurization transient, the pressurizer safety valves are '
not challenged. Therefore, the relaxed main steam line safety valve tolerance is acceptable with respect to the small break LOCA analysis. The increase in PCT for small break LOCA will be reported as a plant design change consistent with the requirements of 10 CFR 50.46.
Post-LOCA hot leg recirculation switchover time is determined for inclusion in emergency procedures to ensure long term core
ULNRC-03627 Attachment 2 Page 6 of 9 cooling by precluding boron precipitation in the reactor vessel following boiling _in the core. This time is dependent on power level as-well as the RCS, refueling water storage tank, and accumulator water masses and boron concentrations. Changes in the steam generator secondary pressure influence the RCS pressure and masses assumed in the switchover analysis. The effect of the proposed main steam line safety valve tolerance relaxation has been evaluated and is insignificant. Further, operation of the pressurizer safety valves will not affect the analysis since calculations are based on total mass inventories.
The LOCA hydraulic forcing functions acting upon the vessel, internals, and loop are a function of the primary system geometry and primary operating conditions. The peak _ forces are generated within the first seconds after break initiation. For this reason, the forces model does not consider the effects of the secondary side. As such, the relaxation in main steam line !
safety valve lift set tolerances to +3% will have no effect on the magnitude or frequency of the LOCA hydraulic forcing functions provided in the Callaway FSAR.
Post-LOCA long-term core cooling will not be affected by an increase in main steam line_ safety valves setpoint tolerances because no change in the sump boron concentration would occur.
Sump boron concentration is determined by the accumulation of all potential water sources in the containment, based on each respective source boron concentration. A scenario has not been envisioned whereby changes in safety valve operation would result in spilling additional non-borated water, reduce the inventory of borated water, or limit component boron concentration as used in the mass average calculation used in the etraluation. It is concluded that there would be no change to the long-term cooling capability of the emergency core cooling system as a result of increased valve tolerances.
Steam Generator Tube Rupture Accident Evaluation The FSAR Steam Generator Tube Rupture (SGTR) analysis is performed to evaluate the radiological consequences of an SGTR accident. The major factors that affect the resultant offsite doses are the amount of radioactivity in the reactor coolant,.the total amount of primary coolant transferred to the secondary side of the ruptured steam generator through the ruptured tube, and the steam released from'the ruptured steam generator to the atmosphere. The amount _of radioactvity in the reactor coolant assumed in the FSAR SGTR analysis is not affected by the changes in the main steam line safety valve setpoint tolerances. An increase in the setpoint tolerance in the positive direction will reduce the calculated break flow and offsite doses.
ULNRC-03627 Attachment 2 Page 7 of 9 Conclusion Revision of the lift setting tolerance to +3/-l% as-found and il%
as-left will have no effect on the relieving capacity of the safety valves. The change in-lift setting tolerance will provide reasonable acceptance criteria taking into account the component service conditiontt and conservative criteria for the as-left condition of the safety valves. It is Union Electric's position that tho' test equipment tolerance (+2/-l%) not be accounted for in the TS tolerance because this equipment tolerance is specifically addressed by the ASME Code. Therefore, as long as the testing equipment and methodology meet the +2/-l% tolerance requirements of OM-1, there is no need to account for testing tolerances in the TS or the safety analysis. (This position is also applicable for the primary safety valves.)
Previous safety analysis conservatively included accumulation in the modeling. Accumulation is no longer modeled for spring loaded MSSVs. This approach is acceptable because the valve setpoint is determined by stem motion and setting the valves on steam. This procedure insures the valves will " pop open" at the TS setpoint. Earlier analysis used accumulation to account for valve chatter prior to opening. This conservatism is no longer required with present testing methods.
The non-LOCA safety evaluation supports the conclusion that the proposed tolerance of +3% for the main steam line safety valves is acceptable. This conclusion is reached based on the assessment that the non-LOCA acceptance criteria are met for this increase in opening setpoints for all the non-LOCA accidents. It is concluded that the tolerances on the main steam line safety valves as given in the TS for Callaway plant may be changed to specify +3/-1%.
The LOCA safety. evaluation supports the conclusion that the effects of increasing main steam line safety valve tolerances to
+3% at Callaway Plant do not result in exceeding any design or regulatory limit. Therefore, it is concluded that the proposed TS valve tolerance relaxation is acceptable.
The increase in safety valve setpoint tolerance from +1% to +3/-
-l% has been evaluated with respect to both LOCA and non-LOCA events for impact on the radiological consequences of accidents.
There is no impact on the radiological consequences of any accident.
The revisions to Table 2.2-1 are made to assess the impact of reducing the high pressurizer pressure safety limit (SAL) from the_ current value of 2445 psig to 2410 psig. This SAL reduction
i ULNRC-03627 Attachment 2 Page 8 of 9 ensures acceptable accident analysis results are obtained to accommodate a relaxation of the main steam safety valve setpoint tolerance to +3/-1%. These changes recognize that older generation Barton transmitters, subject to_ excessive negative drift, are no-longer used in this application. This negative drift accounted for 4.25% of the 4.96% of span Z term. Deletion of this-drift term requires that the S term be increased by 1% of
! span to account for a typical drift allowance. Thus, Z and S are revised to 0.71% span and 2.0% span, respectively. The reduced SAL directly results in a reduced total allowance (TA), i.e.
since it reflects the difference between the SAL and the nominal trip setpoint 2410-2385psig
=3.125% span 800 span /100% span l
The decreased TA in conjunction with the increased S term results in a reduced allowable value of 2393 psig.
Evaluation The proposed change to Technical Specifications does not involve a significant hazards consideration because operation of the Callaway Plant with this change would not:
- 1. Involve a significant increase in the probability or consequences of an accident previously evaluated.
The main steam line safety valves are designed to mitigate transients by preventing overpressurization of the main steam system. The proposed change does not alter this design basis.
The revised analysis shows that the probability or consequences of all previously analyzed accidents are not changed by increasing the setpoint tolerance of the safety valves.
Therefore, there is no increase in the probability of occurrence or the consequences of any accident.
- 2. Create the possibility of a new or different kind of accident from any previously evaluated.
There is no new type of accident _or malfunction created, the method and manner of plant operation will not change nor is there a change in the method in which any safety related system performs its function. Any main steam safety valve lifting at the extremes of the proposed tolerance will not result in a low lift setpoint that is less than the normal no load system pressure or a high lift setpoint that allows main steam system overpressurization.
1
_ _ _ . i
ULNRC-03627 Attachment 2 Page 9 of 9
- 3. Involve a significant reduction in a margin of safety.-
This is based on the fact that no plant design changes are involved'and the method and manner of plant operation remains the {
same. With the increased setpoint tolerance, the main steam )
safety valves will still prevent pressure from exceeding 110 i percent of_ design pressure in accordance with the ASME code. All TSAR accident analysis conclusions remain valid and unaffected by this change.
Conclusion Given the above discussions, the proposed change does not adversely affect or endanger the health or safety of the general public or involve a significant safety hazard.
ULNRC-03627 Attachment 2 Appendix A This appendix describes the method used to analyze the limiting transient (turbine trip) wh.ch could result in a reduction of the capacity of the secondary system to remove heat generated by the reactor coolant system.
1.0 IDENTIFICATION OF CAUSES AND ACCIDENT DESCRIPTION For a turbine trip event, the reactor would be tripped directly (unless below approximately 50% power) from a signal derived from the turbine emergency trip fluid pressure transmitters and turbine stop valve limit switches. The turbine stop valves close rapidly (typically 0.19 seconds) on loss of trip fluid pressure actuated by one of a number of possible turbine trip signals.
Turbine trip initiation signals include:
- a. Generator trip 1
- b. Low condenser vacuum
- c. Loss of lubricating oil I d. Turbine thrust bearing failure j e. Turbine overspeed I-
- f. Manual trip Upon initiation of stop valve closure, steam flow to the turbine stops abruptly. Limit switches on the stop valves detect the turbine trip and initiate steam dump, and, if above 50% power, a reactor trip.
The loss of steam flow results in an almost immediate rise in secondary system temperature and pressure. As a result, the heat transfer rate in the steam generator is reduced, causing the reactor coolant temperature to rise, which in turn causec coolant expansion, pressurizer insurge, and RCS pressure rise. The more rapid loss of steam flow caused by the more rapid valve closure makes a turbine trip a more severe transient than a loss of external electrical load.
The automatic steam-dump system would normally accommodate the
-excess steam generation. Reactor coolant temperatures and pressure do not significantly increase if the steam dump system and pressurizer pressure control system are functioning properly.
If the turbine condenser was not available, the excess steam generation would be dumped to the atmosphere and main feedwater flow would be lost. For this situation, feedwater flow would be A-1
ULNRC-03627 Attachment 2 maintained by the auxiliary feedwater system to ensure adequate residual and decay heat removal capability. Should the steam i
dump system fail to operate, the steam generator safety valves may lift to provide pressure control.
In the event that a safety limit is approached, protection would be provided by the high pressurizer pressure, high pressurizer water level, and overtemperature AT trips. Voltage and frequency relays associated with the reactor coolant pump provide no additional salety function for this event. ta the event that the steam dump valves and steam generator /PORVs fail to open following a large loss of load, the steam generator safety valves may lift, and the reactor may be tripped by the high pressurizer pressure signal, the high pressurizer water level signal, or the overtemperature AT. A turbine trip is classified as an ANS Condition II event, fault of moderate frequency.
A turbine trip event is more limiting than loss of external load, loss of condenser vacuum, and othcr turbine trip related events.
As such, this event has been analyzed for DNBR in detail.
2.0 ANALYSIS OF EFFECTS AND CONSEQUENCES A. M2thod of Analysis In this analysis, the behavior of-the plant is evaluated for a complete loss of steam load from full power without direct reactor trip. This is dene to show the adequacy of the pressure relieving devices, and also to demonstrate core protection margins. The reactor-is-not tripped until conditions in the RCS result in a trip. The turbine is assumed to trip without actuating all the turbine stop valve limit switcheti, The assumption delays reactor trip until conditions in Lne RCS result in a trip due to other signals.
Thus, the analycis assumes a worst-case 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 (except for long-term recovery) to mitigate the consequences of the transient.
The turbine trip transients are analyzed by employing the detailed digital computer code LOFTRAN. LOFTRAN simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generators, and steam generator safety valves. It also computes pertinent plant variables, including temperatures, pressures, and power level. Plant characteristics and initial conditions are discussed in Table 1.
A-2 1
ULNRC-03627 Attachment 2 Major assumptions are summarized be'.ow:
1
- a. Initial Operating Conditions The initial core power, reactor coolant temperature, ,
and recctor coolant pressure are assumed to be at the !
most limiting nominal values. The DNBR calculations are performed using the Improved Design Procedure (ITDP), in which the uncertainties in the initial conditions are included in the DNBR limit value. For the peak RCS pressure calculations, uncertainties of 2%
and 30 psi are applied in the most limiting direction ,
I to the initial core power and-reactor coolant pressure, respectively. Callaway-specific calculations have shown that.a nominal reactor coolant temperature results in conservatively peak RCS pressure '
l calculations.
- b. Moderator and Doppler Coefficients of Reactivity The turbine trip is analyzed assuming minimum l reactivity feedback. These cases assume a moderator temperature coef ficient of 0 pcm/'F and the least negative Doppler coefficient. Maximum reactivity feedback cases have been determined to be non-limiting with respect to both DNB and peak pressure concerns.
l These cases are no longer analyzed,
- c. Reactor conttol From the standpoint of the maximum pressures attained, it is conservative to assume that the reactor is in manual control. If the reactor were in automatic <
control, the control rod banks would move prior to trip and reduce the severity of the transient.
- d. Steam release l No credit is taken for the operation of the steam dump i system or steam generator power-operated relief valves.
The steam generator pressure rises to the point where steam release through safety valves occurs thus l
limiting the secondary steam pressure increase.
l Because these valves are set on steam in a manner that l accounts for accumulation, no accumulation is modeled.
Each steam generator has five valves. The setpoint for each valve is set at the technical specification setpoint plus 3% for setpoint tolerance.
4 A-3
- r,+w+w -- y - w - - - e- ord q y=ee wm+ sus t e ,
ULNRC-03627 Attachment 2
- e. Pressurizer spray and power-operated relief valves Two cases are analyzed:
- 1. For the DNB case, full credit is taken for the effect of pressurizer spray and power-operated relief valves.in reducing or limiting the coolant pressure. The pressurizer safety valves are also available.
- 2. For the overpressure case, no credit is taken for the effect of pressurizer spray and power-operated relief valves in reducing or limiting the coolant pressure. The pressurizer safety valves are operable. This case conservatively accounts for the effects of the pressurizer safety valve loop seals.
- f. Feedwater flow Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No credit is taken for auxiliary feedwater flow since a stabilized plant condition will be reached before auxiliary feedwater initiation is normally assumed to occur; however, the auxiliary feedwater pumps _would be expected to start on a trip of the main feedwater pumps. The auxiliary feedwater flow would remove core decay heat following plant stabilization.
- g. Reactor trip is actuated by the first reactor protection system trip setpoint reached, with no credit taken for the direct reactor trip on the turbine trip.
Trip signals are expected due to high pressurizer pressure (without pressure control), overtempere.ture AT (with pressure control), high pressurizer water level, and low-low steam generator water level. The reactor-trip on turbine trip is credited in selecting design basis events, but is not credited in FSAR Chapter 15 analysis even though it must meet the same protection system design criteria as the rest of the protection system with the_ exception that the seismic design is limited due to a portion of the circuitry being located in the Turbine Building,
- h. The pressurizer safety valves explicitly model the impact of loop seal purgo delay. The setpoint for the
-safety valve is-modeled to lift at the technical specification setpoint (2500 psia) plus 2% (It A-4 j
ULNRC-03627 Attachment 2 tolerance and 1% setpoint shift). Opening of the I safety valves is then delayed by the loop seal purge j delay time (1.15 seconds).
Except as discussed above, normal resctor control systems and engineered safety features are not required to function.
Cases are presented in which pressurizer spray and power-operated relief valves are assumed, but the more limiting l
' cases where those functions are not assumed are also presented. Pressurizer safety valves and/or steam generator safety valves may be required to open to maintain system pressures below allowable limits. No single active failure will prevent operation of any system required to function.
B. Results j The transient responses for a turbine trip from full power l operation are shown for two cases that assume minimum i
reactivity feedback with and without automatic pressure control (Figures 1 through 20). The calculated sequence of events for the accident is show in Table 2.
Figures 1 through 5 show the transient responses for the total loss of steam load with minimum reactivity feedback, assuming full credit for the pressurizer spray and pressurizer power-operated relief valves. No credit is taken for the steam dump. The reactor is tripped by overtemperature AT trip channels. Westinghouse found that the minimum DNBR remains well above the safety analysis limit values. The pressurizer safety valves are actuated for this case and maintain system pressure below 110% of the design value. The steam generator safety valves open and limit the secondary steam pressure increase.
The turbine trip accident was also studied assuming the plant to be initially operating at full power with no credit taken for the pressurizer spray, pressurizer power-operated relief valves, or steam dump. The reactor is tripped on the high pressurizer pressure signal. Figures 11 through 15 show the transient response for this case. The neutron flux remains essentially constant at full power, until the reactor is tripped. In this case, the pressurizer safety valves are actuated, and maintain system pressure below 110%
of the design value.
CONCLUSIONS Results of the analyses show that the plant design is such that a turbine trip without a direct or immediate reactor trip presents A-5 i
Attachment 2 no hazard. The integrity of the core is maintained by opera'. ion of the reactor protection system i.e., the DNBR will be maintained above the safety analysis limit values.
t l
A-6
ULNRC-03627 Attachmont 2 Appendix A TABLE 1:
SUMMARY
OF INITIAL CONDITIONS Loss of Electrical Load Turbine Trip l W/o Control with Control Systems Systems PORVs No Yes Spray No Yes Moderator Density Coefficient Note 2 Note 2
_j AK/X/gm/cc) ")
Moderator Temperature (pcm/'F) 08 Upper Curve of Upper Curve of FSAR Figure FSAR Figure 15.0-2 15.0-2 DNB Correlation NA WRB-2 ITDP No Yes Initial Core Thermal Power (Mwt) 3636 3565 Reactor Coolant Pump Heat (Mwt) 14 1:
Reactor Vessel Coolant Flow (gpm) 374,400 382,630 Vessel T - Avg ('F) 590.9 590.9 Pressurizer Pressure (psia) 2220 2250 Pressurizer Water Volume 1175 1175
( Ft') Note 3 Feedwater Temperature *F 446 446 S/G Tube Plugging Level 15% 15%
Notes: (1) Reactivity Coefficients (2) Function of Moderator Density (3) Does not include surge line volume of 57.4 ft 3 A-7
ULNRC-03627 Attachmsnt 2 i
Appendix A TABLE 2 TIME SEQUENCE OF EVENTS FOR INCIDENTS WHICH RESULT IN A DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM Accident Event Time (sec)
- 1. With pressure control Turbine trip; loss of main 0.0 feedwater flow Initiation of steam 7.6 release from steam generator safety valves Peak RCS pressure occurs 9.4 overtemperature AT 9.8 reactor trip setpoint reached Rods begin to drop 11.0 Minimum DNBR occurs 12.7
- 2. Without pressure Turbine trip; loss of main 0.0 control feedwater flow High pressurizer pressure 5.0 reactor trip setpoint reached Rods begin to drop 6.0 Initiation of steam 7.6 release from steam generator safety valves Peak RCS pressure occurs 7.7 A-8
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ULNRC-03627 Attachment 2 Appendix B l 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, Articles NB-7000. This report documents the overpressure protection provided in the Westinghouse NSSS scope.
2.0 Description of Overpressure Protection 2.1 Overpressure protection is provided for the RCS and its cornponents to prevent a rise in pressure of more + :ian 10%
(Service Level B) above the system design pressure of 2485 )
psig, in accordance with NB-7411. This protection is afforded for the following events which envelope those credible events which could lead to overpressure of the RCS if adequate overpressure protection was not provided.
- 1. Loss of External Electrical Load and/or Turbine Trip
- 2. Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power
- 3. Loss of Forced Reactor Coolant Flow
- 4. Loss of Normal Feedwater Flow
- 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;
- 2. the reactor coolant side of the steam generators;
- 3. reactor coolant pumps;
- 4. a pressurizer attached to one of the reactor coolant loops;
- 5. safety and relief valves; B-1
ULNRC-03627 Attachment 2
- 6. the interconnecting piping, valves and fittings between the principal ccmponents listed abovet and 7 the piping, fittings and valves leading to connecting auxiliary or support systems up to and including the second isolation valve (from the high pressure side) on each line.
2.3 The pressurizer provides volume surge capacity and is designed to mitigate pressure increases (as well as
, decreases) caused by load transients. . A pressurizer spray l 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 percent of full rated load.
The spray nozzle is located in the top head of the pressurizer. Spray is initiated when the pressure-controlled spray demand signal is above a given setpoint.
The spray rate increasca proportionally with increasing compensated error signal until it reaches a maximum value.
The compensated error signal is the output of a proportional plus integral controller, the input to which is an error signal based on the difference between actual pressure and a reference pressure.
The pressurizer is equipped with 2 power-operated relief valves which limit system pressure for a large power mismatch to avoid actuation of the fixed high pressure reactor trip. The relief valves are operated automatically or by remote manual control. The operation of these valves also limits the frequency of opening of the spring-loaded safety valves. Remotely operated stop valves are provided to isolate the power-operated relief valve is excessive leakage occurs. The relief valves are designed to limit the pressurizer pressure to a value below the high-pressure trip setpoint for all design transients up to and including the design percentage step load decrease with steam dump but without reactor trip.
Isolated output signals from the pressurizer pressure protection channels are used for pressure control. These are used to control pressurizer spray and power-operated relief valves in the event of increase in RCS pressure.
In the event of unavailability of the pressurizer spray or power-operated relief valves, and a complete loss of steam flow to the. turbine, protection of the RCS against overpressurization is afforded by the pressurizer safety B-2
ULNRC-03627 Attachmont 2 valves in conjunction 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 420,000 lb/hr for each valve at 2575 psia. The pressurizer safety valves are totally enclosed pop-type, spring-loaded, self-activated valves with backpressure compensation. The set _ pressure of the safety valves will be no greater than system design pressure of 2405 psig (i1%
tolerance) in accordance with Section NB-7511. The pressurizer safety valves and power-operated relief valves discharge to the pressurizer relief tank (PRT). Rupture disks are installed on the pressurizer relief tank to prevent PRT overpressurization. The safety valve flow rates quoted are based on a developed backpressure of 500 psi which is equivalent to 20%-of the safety valves design setpoint.
Figure i shows a schematic arrangement of the primary system pressure-relieving devices.
2.4 Overpressure protection for the main steam system is provided by the steam generator safety valves to prevent a rise in pressure of more than 10% above the steam generator shell-side design pressure in accordance with NC-7411. The-main steam system safety valve capacity is based on providing enough relief to remove 105% of the Engineered Safeguards Design steam flow. - This protection is afforded for the same events as listed in Section 2.1 which envelope those_ credible' events which could lead to system overpressurization if adequate overpressure protection were-not provided.
The set pressure of the lowest _ set main steam safety valve is selected to be the steam generator shell design pressure of 1185 psig. The set pressure of the highest set main steam safety valve is selected to be 1234 psig which ensures that all five main steam safety valves in each steam line are fully open below the maximum prescure limit of 1303.5 psig which is 10% above the design pressure. The three intermediate main steam _ safety valves:are set to open at different,- staggered pressures _between the minimum and maximum set pressures on each steam line.
3.0 Sizing of Pressurizer Safety Valves
-3.1 The sizing of the pressurizer safety valves is based on analysis;of a complete loss of steam flow to the turbine B-3
ULHRC-03627 Attachmont 2 with the reactor operating at 102% of Engineered Safeguards Design Power. In this analysis, feedwater flow is isolated at the start of the transient and no credit is taken for operation of pressurizer power-operated relief valves, pressurizer level control system, pressurizer spray system, rod control system, steam dump system or steam line power-operated relief valves. The reactor is maintained at full l
power (no. credit for reactor trip), and steam relief through the steam generator safety valves is considered. The total pressurizer safety valvo 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. -)M1 analysis demonstrating the conservative nature of this sizing _ procedure is presented in the following section.
3.2 Each of the overpressure transients listed in Section 2.1 has been analyzed and reported in the callaway Plant Final Safety Analysis Report. The analysis methods, computer codes, plant initial conditions and relevant assumptions are also discussed in the FSAR for each transient.
Review of these transients shows that the loss of load / turbine trip event results in the maximum system pressure and the maximum safety valve relief requirements.
In order to support an increase in setpoint tolerance on the main steam safety valves (MSSVs), this pressure-limiting transient was reanalyzed to ensure that all applicable acceptance criteria continue to be met. This transient is presented in detail below.
For a loss of load / turbine trip event, the reactor would be tripped directly (unless below approximately 50% power) from a signal derived from the turbine stop emergency trip fluid pressure and turbine stop valves. The turbine stop valves close rapidly (typically 0.19 second) on loss of trip fluid pressure actuated by one of a number of possible turbine trip signals. This will cause a sudden reduction in steam flow, resulting in an increase in pressure and temperature in the steam generator shell. As a result, the heat transfer rate in the steam generators is reduced, causing the reactor coolant temperature to rise, which in turn causes coolant expansion, pressurizer insurge, and RCS pressure rise.
B-4
__o
ULNRC-03627 Attachment 2 The automatic steam dump system would normally accommodate the excess steam generation. Reactor coolant temperature l and pressure do not significantly increase if the steam dump system and pressurizer pressure control system are functioning properly. If the turbine condenser was not available, the excess steam generation would be dumped to the atmosphere and main feedwater flow would be lost. For this situation, feedwater flow would be maintained by the Auxiliary Feedwater System to ensure adequate residual and l decay heat removal capability. Should the steam dump system fail to operate, the steam generator safety valves may lift to provide pressure control.
In this analysis, the behavior of the unit is evaluated for a complete loss of steam load from the nominal full power level plus a two percent calorimetric error without direct reactor tript that is, the turbine is assumed to trip without actuating all the sensors for reactor trip on the turbine stop valves. This assumption delays reactor trip j 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 the turbine trip, with no credit taken for auxiliary feedwater to mitigate the consequences of the transient.
The loss of load / turbine trip transient is analyzed by employing the detailed digital computer program LOFTRAN.
The program simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generators, and steam generator safety valves. The program computes pertinent plant variables including temperatures, pressures, and power level.
Major assumptions are summarized below.
- a. Initial operating conditions The init.al reactor power is assumed to be at nominal full power plus a calorimetric error; the initial pressure is assumed to be nominal minus an appropriate pressure uncertainty to allow for errors in the pressurizer pressure measurement and control channels.
The average RCS temperature is assumed to be at the nominal full power value. This results in the maximum possible increase in coolant pressure for the loss of load / turbine trip event.
B-5
ULNRC-03627 Attachment 2
- b. Moderator and Doppler coefficients of reactivity The analysis assumes a zero moderator temperature coefficient and a least negative Doppler power defect.
Part-power cases analyzed assuming a positive moderator temperature coefficient, consistent with BOL conditions, were shown to be less limiting with respect to peak RCS pressure.
- c. Reactor control From the standpoint of the maximum pressures attained, it is conse"vative to assume that the reactor is in manual control. If the reactor were in automatic control, the control rod banks would move prior to trip and reduce the severity of the transient.
- d. Steam release-No credit is taken for the operation of the steam dump system or steam generator power-operated relief valves.
A staggered main steam safety valve model is used such that each valve can be properly modeled to lift and be fully open at 3% above its setpoint. The 3% setpoint uncertainty accounts for safety valve setpoint tolerance. Using this model, the steam generator pressure rises until four of the five main steam safety valve setpoints are reached. Steam release through four of the five main steam safety valves on each steam line limits secondary steam pressure to levels well below the 110% of shell design pressure,
- 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 limiting the coolant pressure. All three safety valves are operable.
The modeling of the three pressurizer safety valves uses approved methodology (Reference 10) to account for the effects of the pressurizer safety valve loop seals.
A pressurizer safety valve setpoint uncertainty of +2%
and 1.15-second loop seal purge time are assumed in the analysis. The 2% setpoint uncertainty includes a 1%
set pressure shift and 1% set pressure tolerance. No steam flow is assumed until the valve loop seals are B-6
ULNRC-03627 Attachment 2 purged. All three of the code safety valves are operable as required by plant Technical Specifications,
- f. Feedwater flow Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No credit is taken for auxiliary feedwater flow since a stabilized plant condition will be reached before auxiliary feedwater initiation is normally assumed to occurt however, the auxiliary feedwater pumps would be expected to start on a trip of the main feedwater pumps. The auxiliary feedwater flow would remove core decay heat following plant stabilization,
- g. Reactor trip Reactor trip is actuated by-the first Reactor Protection System trip setpoint reached with no credit taken for the direct reactor trip on the turbine trip.
Trip signals are expected due to high pressurizer pressure, overtemperature AT, high pressurizer water level, and low-low steam generator water level.
The results of the loss of load / turbine trip transient are shown on Figures 2, 3 and 4. The reactor is tripped on a high pressurizer pressure signal. Figure 2 shows the nuclear power and the reactor coolant loop hot leg and cold leg temperatures for this transient. Figure 3 shows pressurizer pressure and reactor coolant pump discharge pressure, which is the point of highest pressure in the RCS.
It also shows the pressurizer safety valve relief rate which remains below the minimum required capability assumed in the analysis: 350 lbm/sec. Figure 4 shows the steam generator she,'.1 side pressure and main steam safety valve relief rate per steam generator. This last figure indicates that four of the five valves on each steam line are actuated during the loss of load / turbine trip accident.
The results of these analyses show that the overpressure protection provided is sufficient to maintain peak RCS pressure and the main steam system pressure below the code limit of 110% of the respective system design pressures.
The plot of pressurizer safety valve relief rate shows that adequate overpressure protection for this limiting event could be provided by about 88% of the installed safety valve capacity.
B-7 i
)
ULNRC-03627 Attachment 2 4.0 References
- 1. ASME Boiler and Pressure Vessel Code,Section III, Articles NB-7000, 1971 and 1974 Editions
- 2. " Topical Report - Overpressure Protection for Westinghouse Pressurized Water Reactors," WCAP-7769, Rev. 1, June 1972
- 3. "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary), WCAP-7907-A (Nonproprietary), April 1984 :
- 4. Callaway Certified Safety Valve Capacity, purchase order number 250052, quality releaso number 40915 (valve serial number N60446-00-0006) and quality release number 40937 (valve serial numbers N60446 0004 and N60446-00-0005)
- 5. Callaway OPPR Loss of Load / Turbine Trip Analysis for Increased MSSV Tolerance, Calculation No. CN-TA-94-126, August 1994 (Proprietary)
I
- 6. Callaway Rod Withdrawal at Power Analysis, Calculation No. CN-TA-87-002, January 1987 (Proprietary)
- 7. Callaway Loss of Reactor Coolant Flow Analysis, Calculation No. CN-TA-86-223, February 1987 (Proprietary)
- 8. Callaway Loss of Normal Feedwater/ Station Blackout Analysis, Calculation No. CN-TA-86-251, January 1987 (Proprietary)
- 9. SNUPPS Deletion of Reactor Trip on Turbine Trip Below 50% Power Analysis, Calculation No. CN-RPA-79-12, January 1979 (Proprietary)
- 10. " Pressurizer Safety Valve Set Pressure Shift," WCAP-12910 Rev.1-A (Proprietary), May 1993 B-8
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ULNRC 03627 ATTACllMENT 3 ENVIRONMENTAL CONSIDERATION I
ULNRC-03627 Attachment 3 Page 1 ofil ENVIRONMENTAL CONSIDERATION This proposed amendment revises Table 3.7-2 to specify that the lift setting tolerance for the main steam line safety valves is
+3/-1% as-found and +/-1% as-left. Table 2.2-1 is revised by reducing the sensor error for the pressurizer pressure-high trip. Revising the error in this manner provides margin to relax the setpoint tolerance for the main steam line safet'j valver.
l The proposed amendment involves changes with respect to the use-of facility components located within the restricted area as ;
defined -in 10 CFR Part 20. Union Electric has determined that i the. proposed amendment does not involve:
l l 1. A significant hazard consideration, as discussed in Attachment 2 of this amendment application; 1
- 2. A significant change in the types or significant increase in the amounts of any effluents that may be released offsite;
- 3. A significant increase in ir.dividual or cumulative occupational radiation exposure.
Accordingly the proposed amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22 (c) (9) . Pursuant to 10 CFR 51.22 (b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of this amendment.
.