ML20125D213
| ML20125D213 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 12/04/1992 |
| From: | VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.) |
| To: | |
| Shared Package | |
| ML20125D197 | List: |
| References | |
| NUDOCS 9212150053 | |
| Download: ML20125D213 (86) | |
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ATTACHMENT 1
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- PROPOSED TECHNICAL SPECIFICATIONS CHANGES NORTH ANNA UNIT 1-4 h
VIRGINIA ELECTRIC AND POWER COMPANY I
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h-TABLE 2.2-1 E
REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS E
l FUNCTIONAL UNIT TRIP SETPOINT ALLOWABLE VALUES i
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.1.
Manual Reactor Trip Not Applicable Not applicable
,2.
. Power Range, Neutron Flux Low Setpoint - s 25% of RATED Low Setpoint - s 26% of RATED THERMALPOWER THERMALPOWER High Setpoint - s 109% of RATED High Setpoint - s 110% of RATED THERMALPOWER THERMALPOWER 3.
Power Range, Neutron Flux, s 5% of RATED THERMAL POWER with s 5.5% of.iATED THERMAL POWER s
High Positive Rate a time constant 2 2 seconds with a time constant 2 2 seconds 4.
Power Range, Neutron Flux, s 5% of RATED THERMAL POWER with s 5.5% of RATED THERMAL POWER High Negative Rate a time constant 2 2 seconds.
with a time constant 2 2 seconds 5.
Intermediate Range, Neutron s 25% of RATED THERMAL POWER -
s 30% of RATED THERMAL POWER -
Flux 6.-
Source Range, Neutron' Flux s 105 counts per second s 1.3 x 105 counts per second 7.
Overtemperature AT See Note 1 See Note 3 8.
< Overpower AT -
See Note 2 See Note 3 j
9.
~ Pressurizer Pressure--Low 21870 psig 2 1860.. psig I
c 5 2385 psig s 2395 psig
- 10. Pressurizer Pressure--High
- 11. Pressurizer Water. Level--High 5 92% of instrurient span s 93% of instrument span 1
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- 12. Loss of Flow' 2 90%'of design flow per loop
- 2 89% of design flow per loop
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- Design flow per loop is one-third of the minimum allowable Reactor Coolant System Total Flow Rate as specified in Table 3.2-1.
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U DNB PARAMETERS m-LIM!TS r
2 Loops in Operation" 2 Loops in Operation" l
3 Imps in
& Loop Stop
& Isolated Loop PARAMETER Ooeration Valves Onen 3109 'iaives Closed Aeactor Coolant System Tavg s 591*F g
Pressurizer Pressure
- 2. 2205 psig*
Reactor Coolant System 2 275,300 gpm
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.g Total Flow Rate
- Umit not applicable during either a THERMAL POWER ramp increase in excess of 5% RATED THERMAL POWER per minute or a i
THERMAL POWER step increase in excess of 10% RATED THERMAL POWER.'
" Values dependent on NRC approval of ECCS evaluation for these conditions.
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ATTACHMENT 2 e
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DISCUSSION OF CHANGES 1
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DISCUSSION OF CHANGES INTRODUCTION AND BACKGROUND As required by Technical Specifications 3.2.5 and 4.2.5.2, North Anna Unit 2 performs Reactor Coolant System (RCS) flow rate measurements-once per fuel cycle. The North Anna Unit 2 safety analyses are based in part on verifying, via the Technical Specifications surveillance, that-the RCS total flow rate is greater than or equal to 284,000 gallons-per minute.
(gpm).
The additional steam generator tube plugging anticipated during the next several cycles increases the likelihood ~~of violating this
. Technical Specifications requirement.
Therefore, -safety -analyses and evaluations have been performed which support a reduction in the minimum RCS total flow rate limit' to 275,300 gpm.
The-' attached evaluation has-({
been prepared to support the Technical Specifications changes associated with the reduction in the minimum RCS total flow rate limit.
SPECIFIC CHANGES
- The predictions of future cycle steam generator tub'e plugging are such that_ the RCS total. flow rate measurement may not continue to meet-the
.l current _ Technical Specifications requirement of-2284,000 gpm.
The proposed Technical Specifications changes implement' a reduced minimum total flow rate requirement which is intended to bound future measured flow values and required steam generator tube plugging.
Specifically, the proposed Technical Specifications changes are being-requested to reduce the RCS total flow rate requirement to 2275,300 gpm, which is an approximately 3% reduction from the current Technical Specifications requirement.
The proposed = Technical ' Specifications changes " affect Table 2.2-1, Reactor Trip System LInstrumentation Trip Setpoints,-
(Technical Specification 2.2.1)- and Table 3.2-1, DNB. Parameters _(Technical Specification 3.2.5).
These : proposed Technical-Specifications ' changes will : permanently revise' the footnote on the bottom of Table 2.2-1,- Reactor-Trip _ System Instrumentation Trip Setpoints, to specify that the " design flow per_ loop" is "one-third of the' minimum allowable Reactor : Coolant. System -Total Flow Rate as specified in Table' 3.2-1."
This proposed change -removes _: the actual numeric : value for-loop design flow and replaces - _.i t with-a description of the derivation of--the value. _In effect, this change'will ensure L eonsistency between thec requirements of' this table : and f the requirements -of' Table. 3.2-1.
This. change.will : eliminate the - need to change _this: requirement in the future without affecting the significance-of the reactor trip setpoint: value. The. trip setpoint of "190% of _ design -
flow per loop" ensures that' Safety Analysis. assumptions will'be met.
The proposed Technical Specifications changes will also revise Table 3.2-1,:0NB Parameters, by reducing the-minimum limit for Reactor Coolant System Total - Flow Rate from 284,000 gpm to 275,300 gpmi The proposed reduction in the minimum : measured RCS flow - rate is: necessary to
accommodate the expected increase in RCS loop resistance caused by increased steam generator tube plugging levels.
The attached safety evaluation addresses the safety significance of the proposed changes to the North Anna Unit 2 Technical Specifications, t
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SAFETY EVALUATION i.
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SAFETY EVALUATION IN SUPPORT OF REDUCED MINIMUM RCS TOTAL FLOW RATE NORTil ANNA UNIT 2
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TABLE OF CONTENTS Page Table of Contents.......................................
2 1.0 Introduction..
3 2.0 Safety Analysis.........................................
6 i
2.1 Summary of Safety Analysi s Input Changes.........
6 2.2 Evaluation of Retained DN3R Margin...............
9 2.3 Impact of Flow Reduction on Core Thermal Limits and Reactor Protection System Setpoints.........
11 2.4 Summary of Accident Evaluations.................
13 2.5 S ammary of Reanalyzed Accidents.................
35 2.5.1 Loss of External Load................
36 2.5.2 Loss of Normal Feedsater..............
40 2.5.3 Rod Bank Wi thdrawal at Power..........
45 2.5.4 Complete Loss of Flow.................
49 2.5.5 Lock %d Rotor / Sheared Shaft.............
55 3.0 NSSS and Balance of Plai,t Systems and Components.......
59 4.0 Conclusions............................................ 67 References.............................................
69 Appendices.............................................
72 1.
Description of Retained DNBR Margin Accounting Method.................................
73 II. Approach for Assessing the UFSAR Chapter 15 Accidents..............................
75 2
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1.0 INTRODUCTION
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The purpose of this report is to present the analyses and evaluations performed by Virginia Electric and Power Company to justify operation with a reduced minimum Reactor Coolant System (RCS) flow rate associated with i
increased Steam Generator Tube Plugging (SGTP)' levels.
The physical consequences of increased SGTP are primarily (a) increased RCS loop resistance, resulting in a lower RCS flow rate, (b) decreased steam
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generator tube heat transfer area, resulting in lower steam generator outlet steam pressure, and (c) a decreased total RCS volume. -The impact of these changes with respect to previously analyzed design conditions must be fully assessed for both normal operating and accident conditions.
This assessment is perfortaed following a ~ steam generator inspection. When required, revised safety analyses are performed and a Core Operating Limits Report (COLR) is prepared as required by Technical Specification
' 6.9.1.7.
In many cases, the incorporation of revised safety analyses into:the j
~
North Anna design basis could be accomplished via Virginia Electric and-Power Company processes - employed to assess changes per 10 CFR 50.59.
However, to accommodate future operation of North Anna 2 with increased L
SGTP levels, a change to the Technical-Specifications minimum allowable-Reactor Coolant System Total-- Flow Rate. (referred to hereaf ter as " minimum meesured: flow'. rate")1-is'being, pursued.
The safety. analyses and~
evaluations documented:in.this report.have been prepared to support the
. Technica1' Specifications ~ changes for a reduced minimum met.sured fiow rate
- associated with' increased' steam generator ; tube-plugghg.- This report
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follows the format of the North Anna Unit I reduced RCS flow rate evaluation previously submitted and approved by the NRC in References (21) and (22).
An increase in the average tube plugging causes an increase in loop j -
resistance, which reduces the RCS total flow rate passing through the core.
When this flow rate becomes less than that assumed in accident analyses, it can have a significant effect on key analysis results.
The latest Unit 2 flow measurement, taken April 29, 1992 at an average SGTP level of 7.0%, was 293,321 gpm versur a Technical Specifications limit of 284,000 gpm. In order to conservatively bound the flow rates resulting from future increases in tube plugging, Virginia Electric and Power Company is proposing a Technical Specification minimum me sured flow of 1
275,300 gpm to accommodate averago SGTP levels up a soni.wimately 18%.
1 Since the RCS total flow rate is critical input assumption in the UFSAR Chapter 15 analyses, it is nece:..ary to evaluate all Chspter 15 analyses to support the implementation of increased SGTP at North Anna Unit 2.
4 Although the impact of reduced RCS flow rate and extended SGTP on many JFSAR transients was evaluated on the basis of parameter sensitivities a,d analysis margin, several transients were explicitly. reanalyzed.
These reanalyzed transients include the Loss of External Load (Section 2.5.1), the Loss of Normal Feedwater (Section 2.5.2), the Rod Bank Withdrawal at Power (Section 2.5.3), the Complete Loss of Flow (Section 2.5.4) and the Locked Reactor Coolant Pump fotor Event (Section 2.5.5).
Descriptions of these transient reanalyses, along with the evaluations 4
of transients not reanalyzed, are presented in appropriate detail in this report.
For the North Anna Unit 1 extended SGTP analyses (72), Westinghouse and Stone arid Webster have provided evaluations of the impact of reduced RCS flow rate and extended SGTP upon the NSSS and Balance of Plant systems and components. These evaluations have confirmed the ability of each system and component to perform its respective design function under the reduced RCS flow rate conditions.
Section 3.0 ' summarizes these evaluations. An assessment of the Unit 1 evaluations has confirmed that the conclusions will remain valid for the operating conditions associated with the 275,300 gpm RCS flow rate limit on Unit 2.
The conditions assumed in the safety evaluations described in this report bound the operating conditions capable of being achieved by North Anna Unit 2 under conditions of increased SGTP.
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2.0 SAFETY ANALYSIS 2.1 SUttiARY OF SAFETY ANALYSIS INPUT CllANGES As described in Section 1.0, the physical consequences of extended SGTP are primarily (a) increased reactor coolant system (RCS) loop resistance, resulting in a lower RCS flow rate, (b) decreased steam generator tube heat transfer area, resulting in lower steam generator outlet steam pressure, and (c) a decreased total RCS volume.
Revised safety analyses or evaluations were performed to assess the impact of the proposed increased SGTP on previously analyzed design conditions during both normal operating and accident conditions.
A revised RCS minimum measured flow rate of 275,300 gpm, which is approximately 3% lower than the current TS 3.2.5 RCS flow rate, was selected for the extended SGTP analyses based on experience gained during the North Anna Unit 1 extended SGTP effort in assessing measured RCS flow rate vs. steam generator ' tube' plugging fractions.
This value is appropriate for use in statistical Departure from Nucleate Boiling (DNB)
I accident analyses.
Similarly, for deterministic DNB and non-DNB analyses, a thermal design flow rate of 269,800 gpm was selected.
This value includes a 2% allevance for flow measurement uncertainty.
.The accident reanalyses discussed in Section 2.5 assume an average RCS temperature of 586.8'F and 2893 K4 core thermal power.
These are the l
current nominal Technical Specifications values. Available analyses anil l'
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assessments demonstrate that the conclusions drawn herein are valid for full power RCS average temperatures as low as 580.8'F for Unit 2.
The bounding core physics parameters assumed in the most recent Unit 2 Reload Safety Evaluation were assumed in all transient reanalyses.
Table 2.1-1 provides additional information on key analysis assumptions.
Steam generator steam pressure is reduced as a function of steam generator tube plugging level.
For the Unit I reduced flow evaluation, Westinghouse developed revised design steam pressures of 766 psia at 30%
SGTP, 740 psia at 35% SGTP, and 711 psia at 40% SGTP. These revised steam pressures have been incorporated into analysis models at the SGTP level appropriate for the specific transient analysis. An evaluation of these Unit I non-LOCA transient analyses confirmed that they bound the Unit 2 reduced flow conditions.
Revised one-and two-loop RETRAN (2),(3) models were developed which explicitly account for the effects of extended SGTP on RCS flow, RCS loop flow resistance, steam generator heat transfer area, steam generator tube metal volume (heat capacity), and secondary side steam pressure.
These models were utilized in the reanalyses discussed in Section 2.5.
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t TABLE 2.1-1 i
KEY ANALYSIS ASSUMPTIONS DETAILS Initial Conditions 4
Statistical Deterministic DNB Method Method a
Power 2893.0 MWt 2950.86 MWt Average Temperature 586.8 'F 590.8 'F RCS Flow Rate 275,300 gpm 269,800 gpm Pressure 2250 psia 2187/2280 psia FAh at Rated Power 1.49 1.55 1.55-Cosine Axial Power Profile 8
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2.2 EVALUATION OF RETAINED DM3R MARGIN i
i The Statistical Departure from Nucleate Boiling Ratio _(DNBR)
Evaluation Methodology (4) implementation analysis for North Anna Unit 2 (5),(6) established a statistical _DNBR limit'(SDL) of 1.26.
The difference between this value and = the WRB-1: Critical Heat Flux (CHF) correlation (7),(8) limit of.1.17 represents the impact of-combining key.
DNBR analysis parameter uncertainties in a statistical manner.. Transient.
analysis results are assessed against a 1.46 design DNBR limit.
The percentage difference between the design DNBR-limit and the SDL represents generic retained margin, against which penalties may be assessed to account-for the DNB effect of changes in plant operating conditions or analysis methodology. Analysis DNBR margin is the percentage difference l
between the minimum -transient analysis DNBR and the design DNBR limit.
Although it is atypical, this margin.has been occasionally utilized-to' l
justify changes in plant operating conditions.
The assessment 'of penalties against generic retained. margin is typically accomplished through the use-of_a'DNBR partial derivative.
To-
' facilitate the evaluation.of the-proposed reduction' in minimum RCS flow rate, the maximum DNBR _ partial derivative with ' respect to RCS flow rate l
was calculated by examining the marginal ef fect of changes _ in RCS flow rate.on DNBR-.over a range of. operating conditions.
The product of the percentage reduction _in.. RCS ' flow' rate,. 'and the bounding' DNBR partial
- derivative with respect to flow, provides a penalty which may be assessed.
against available retained margin-to: account -for the effect of:the RCS flow rate-reduction.-
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A DNBR penalty of 4.8% was calculated based on a reduction of 3.0% in RCS minimum measured flow rate, and a bounding WRB-1 DNBR partial j
derivative of 1.6% (% change in DNBR / % change in flow).
It has been determined that there is adequate available generic retained DNBR margin
}
to accommodate this penalty without taking credit for analysis margin.
l A description of the retained DNBR margin accounting method is provided in Appendix 1.
(This text was provided to the NRC staff previously in Reference (25).)
As discussed in Section 2.3, this penalty will be
)
extractad from available Core Thermal Limit retained DNBR margin to ensure 4
that bounding Core Thermal Limit protection is provided by the existing OTAT and OPAT reactor protection system functions for flow rates as low as the proposed reduced minimum measured flow rate. The DNBR penalty will also be applied to those transiants which were not reanalyzed, but were evaluated and determined to require a DNBR penalty to account for the ef fect of the flow reduction on minimum predicted transient DNBR.
Those transients which were reanalyzed require no penalty to be assessed, as the reanalyses explicitly accounted for the ef fects of a reduced RCS flow l
rate (and other effects related to steam generator tube plugging).
It is recognized that the assessment of a DNBR penalty against retained margin in the manner described above neglects any effect of the flow rate reduction on transient dynamics.
The reduction in RCS flow rate is, in general, sufficiently small that the impact of the flow reduction on transient dynamics is offset by the use of a bounding DNBR partial derivative.
All cases for which this assumption might be questionable have been explicitly--reanalyzed.
(See Section 2.5.)
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2.3 IMPACT OF FLOW REDUCTION ON CORE THERMAL LlHITS AND REACTOR PROTECTION SYSTEM SETP0lNTS An evaluation has been performed to assess the impact of the proposed reduction in minimum measured flow rate on North Anna Unit 2 core thermal limits, overtemperature and overpower AT ' trip setpoints, and the F(AI) function.
The current Core Thermal Limits in Figure 2.1-1 of the Technical Specifications consist of two distinct limits. The DNBR portions of the limit lines are based on a RCS flow of 289,200 gpm and bound a design DNBR limit of 1.46 (vice a statistical DNBR limit of 1.26).
The vessel exit portions of the limit lines are based on a thermal design flow of 278,400 gpm. The Overtemperature AT protection setpoints are devised to generate a reactor trip should any combination of plant conditions exist which would cause any of these limit lines to be violated.
The protection setpoints are calculated using a static analysis of plant conditions.
l The proposed reduced minimum measured flow rate of 275,300 gpm is used for statistical DNBR analysis.
A penalty against retained DNBR margin was defined in Section 2.2 to compensate for the impact of the reduction in minimum measured flow rate.
Similar to the previous RCS flow rate reduction to a minimum measured flow of 284,000 gpm (9) ard the recent North Anna 1 flow reduction to a minimum measured flow rate of 275,300 l
gpm (21),(22), there is sufficient retained margin in the Core Thermal l
Limits to absorb this penalty.
Therefore, the DNB portions of the existing core thermal limits continue to remain bounding.
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The vessel exit boiling limited portions of the core thermal limits were evaluated with the proposed reduced non-statistical (deterministic) thermal design flow rate of 269,800 gpm (which corresponds to a minimum measured flow rate limit of 275,300gpm). A review of the current vessel exit boiling limits shows that they contain more than enough conservatism to of fset the small impact of the reduced desig'i flow.
Therefore, the Core Thermal Limits established 19 the Technical Specifications remain bounding for operation at the reduced RCS flow rate.
The existing Technical Specifications OTAT and OPAT setpoints and the F(AI) function were demonstrated to provide bounding protection for the proposed reduced minimum measured flow rate.
This included specific accident reanalysis as indicated in this report.
For those DNB-limited transients which were not reanalyzed, bounding protection is attained by the assessment of a DNBR penalty against available retained DNBR margin to compensate for the impact of the reduction in minimum measured flow l
l rate.
The development of this penalty was discussed in Section 2.2.
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2.4
SUMMARY
OF ACCIDENT EVALUATIONS J
This section discusses the UFSAR Chapter 15 accidents for which evaluations were performed to support a reduction in the Technical Specifications Reactor Coolant System Total Flow Rate (" minimum measured flow rate") associated with increased SGTP at North Anna Unit 2.
For each accident, a brief description of the transient, its analysis, and how the i
analysis is impacted by the reduced RCS flow rate is provided.
A j
discussion is provided which demonstrates that the impact of the proposed flow reduction on the accident analysis results is accommodated by current analysis margins.
Section 2.5 provides descriptions of the reanalyses performed for those transients which were determined by evaluation to be l
potentially impacted by the proposed reduction in the Technical Specifications minimum measured RCS flow rate associated with increased SGTP.
(Appendix 11 provides a description of the approach used for assessing which UFSAR Chapter 15 Accidents would be reanalyzed. This text was provided to the NRC staff previously via Reference (25).)
2.4.1 Accidental Depressurization of the RCS (UFSAR Section 15.2.12).
The most severe core conditions resulting from an accidental depressurization of the reactor coolant system are associated with the i
inadvertent opening of a pressurizer safety valve.
Initially, the event results in a rapidly decreasing reactor coolant system pressure until this pressure reaches a value corresponding to the hot-leg saturation-pressure.
At that time, the pressure decrease is slowed considerably.
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The pressure continues to decrease, however, throughout the transient.
The effect of the pressure decrease would be to decrease the neutron flux via the moderator density feedback, but the reactor control system (if in the automatic mode) functions to maintain the power essentially constant throughout the initial stage of the transient.
The average coolant temperature decreases slowly, but the pressurizer level increases until reactor trip, l.
The analysis of the Accidental Depressurization of the RCS transient is performed to ensure that the minimum DNBR remains above the DNBR design limit throughout the transient.
The impact of reduceJ RCS flow due to increased SGTp on the DNBR results of the Accidental Depressurization of the RCS analysis has been fully accommodated by a single penalty assessed against available retained DNBR margin.
The development of this penalty is described in Section 2.2.
2.4.2 Accidental Depressurization of the Main Steam System l
(UFSAR Section 15.2.13).
The most severe core conditions resulting from an accidental j.
denressurization of the main steam system are associated with an inadvertent opening of a single steam dump, relief, or safety valve. ' The analyses performed-in consideration of a main steam pipe rupture are presented in UFSAR Section 15.4.2.1 (Main Steamline Break Accident).
I The steam release which occurs.during this accident removes anergy from the RCS, causing a reduction in RCS temperature and pressure.
In the 14
presence of a negative moderator temperature coefficient, the cooldown results in a reduction of core shutdown margin.
The current evaluation is performed to demonstrate that, in the presence of a stuck rod cluster control assembly and a single failure in the engineered safety features, there will be no departure from nucleate boiling in the core for a steam release equivalent to the opening (with failure to close) of the largest of any single steam dump, relief, or safety valve.
Increased SGTP reduces the steam generator's capacity to remove energy from the RCS.
Because the primary effect of an cccidental depressurization of the main steam system is to decrease RCS temperature and pressure, and to increase core power (given an end-of-cycle negative moderator temperature coefficient), a reduced capacity to remove energy from the RCS due to increased SGTP would act to further limit the severity of the reactor coolant temperature decrease. The impact of a 3 reduction in RCS flow rate is accommodated by a penalty assessed against available retained DNBR margin.
In addition, analysis margin (margin between the minimum analysis ONBR and the design DNBR limit) is substantial for this event.
Therefore the existing UFSAR analysis conclusions will remain valid for the reduced RCS flow condition.
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2.4.3 CVCS Malfunction (Boron Dilution) (UFSAR Section 15.2.4).
A reduction in the minimum measured flow rate has no -direct consequences on the analysis of the boron dilution event.
The presently 15
specified NA-1&2 TS 3.1.1.3.2 precludes the possibility of an unplanned boron dilution by specifying that the primary grade water flow control valve be locked closed during operations in Modes 3, 4, 5, and 6 except during planned boron dilution or makeup activities.
The current SRP (Standard Review Plan) acceptance criteria are met through this presently specified NA-l&2 15 3.1.1.3.2.
As a reactivity insertion transient, the consequences of a boron dilution event at power (in terms of approach to the design DNBR limit) are bounded by those of the rod bank withdrawal event, which was reanalyzed as described in Section 2.5.3.
The impact on the boron dilution at power analysis of the reduction in RCS volume due to increased SGTP has already been considered.
The current boron dilution analysis of record accounts for up to 25% tube plugging. Therefore, no reanalysis of this event is required to support the proposed Technical Specifications changes.
2.4.4 Excessive Load Increase (UFSAR Section 15.2.11).
An excessive load increase is defined as a rapid increase in the steam flow that causes a power mismatch between the reactor core power and the steam-generator load demand.
The reactor control system is designed to accommodate a 10% step load increase or a 5%/ minute ramp load increase in the range of 15 to 100% of full power. Any loading rate in excess of these values may cause a reactor trip actuated by the reactor protection system.
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The end of life cases (with and without automatic rod control) were demonstrated to be limiting, since the RCS cooldown due to load increase has the maximum impact on core power at end of life.
In both the automatic and manual reactor control end-of-life cases, the DNBR remains well above the DNBR limit.
The impact of reduced RCS flow due to increased SGTP on the DNBR results of the Excessive Load increase analysis has been fully accommodated by a single penalty assessed again:t available retained DNBR margin.
The development of this penalty is described in Section 2.2.
2.4.5 Excessive Heat Removal (Feedwater Halfunction)
(UFSAR Section 15.2.10).
Reductions in feedwater temperature or additions of excessive feedwater are means of increasing core power above full power.
Such transients are attenuated by the thermal capacity of the secondary plant and of the reactor coolant system.
The reactor protection system (high flux, overtemperature delta-T (OTAT), and overpower delta-T (0 PAT) trips) prevents any power increase that could lead to a DNBR less than the limit value.
For the currently applicable analyses of both the automatic and manual reactor control end-of-life cases, the DNBR remains well above the DNBR limit.
The impact of reduced RCS flow rate due to increased SGTP on the DNBR results of the Excessive Heat Removal analysis has been accommodated 17
by a single penalty assessed against available retained DNBR margin. The development of this penalty is described in Section 2.2.
2.4.6 Control Rod Drop /Hisalignment (UFSAR Section 15.2.3).
When operating at power, a single or multiple dropped control rod may result in a transient leading to reduced margins to fuel design limits and, in particular, to DNB limits.
This would be a result of increased power distribution peaking factors with the inserted (dropped) rods and a possible " return to power" transient produced by feedback or automatic control. Depending on the control system, the " return to power" transient could result in a power level in excess of the initial level.
Normally the plant is protected from exceeding DNB limits through a negative flux rate trip system. The system will sense the initial rapidly decreasing neutron flux (as a negative rate) and trip the reactor to end the event.
For some events, however, the flux decrease rate may be insufficient to generate a trip.
Reference (10) describes a dropped rod analysis methodology developed by Westinghouse and funded by the Westinghouse Owner's Group (WOG). This methodology is an extension of the methodology of Reference (11) and eliminates the need to take credit for the negative flux rate trip.
Virginia Electric and Power Company implemented the Westinghouse methodology for performing the dropped rod analyses using the methods of Reference (10), although the negative flux rate trip has been retained 18
at North Anna.
Virginia Electric and Power Company has performed evaluations which show the applicability of the methodology, the correlations, and the transient database for analysis of the dropped rod event for North Anna Units 1 and 2 using Virginia Electric and Power Company core design and transient analysis computer codes.
Dropped rod DNBR limit lines applicable to reduced RCS flow conditions have been developed for application of the Reference (10) methodology to rele:d cores designed under conditions of reduced flow.
Because these limit lines are specifically applicable to conditions of reduced flow, no cycle-specific penalty against available DNBR retained margin need be assessed.
Future operation of North Anna Unit 2 reload cores will be assessed against these revised dropped rod limit lines.
2.4.7 Partial Loss of Flow (UFSAR Section 15.2.5).
A partial loss of coolant flow accident can result from a mechanical or electrical failure in a reactor coolant pump, from a fault in the power supply to the pump, or from inadvertent closure of a loop 1 solation valve.
If the reactor is at power at the time of the accident, the immediate effect of loss of coolant flow is a rapid increase in the coolant temperature.
This increase could result in DNB with subsequent fuel damage if the reactor is not tripped promptly.
The results of the partial loss of flow accident analysis are bounded by those of the complete loss of flow event, which is reanalyzed in Section 2.5.4.
Because the event has not been explicitly reanalyzed to 19
evaluate the impact of the reduced RCS flow rate associated with increased SGTP, the impact has bt a accommodated by a single penalty assessed against available retained DNBR margin.
The development of this penalty is described in Section 2.2.
2.4.8 Rod Withdrawal from Subcritical (UFSAR Section 15.2.1).
A rod cluster control assembly withdrawal accident is defined as an uncentrolled addition of reactivity to the reactor core caused by withdrawal of the rod cluster control assembly, thereby producing a power e x c ursi or..
Potential causes of the event include malfunctions of the reactor control and control rod drive systems, and operator error.
At cold shutdown, protection against the consequences of this accident are provided by the high source range count rate trip.
At hot standby and hot shutdown, protection is provided by the source range trip.
During startup and at power, protection is provided by the intermediate range or power range high neutron flux reactor trips, or by the intermediate and power range rod stops.
The neutron flux response to a continuous reactivity insertion is characterized by an exponential increase.
Once the amount of reactivity inserted equals the ' delayed neutron fraction for the core, the power increase is very rapid, and is terminated by the reactivity. feedback effect of the negative Doppler coefficient. This self-limitation of the power burst is of primary importance since it limits the power to a tolerable level during the delay time for protective action.
This event 20
is non-limiting from a DNBR standpoint since the peak heat flux attained during the transient is substantially below that at hot full power.
The impact of a reduction in RCS flow rate due to increased SGTP on the DNBR results of the rod withdrawal from subcritical analysis has been fully accommodated by a single penalty assessed against available retained DNBR margin.
The development of this penalty is described in Section 2.2.
2.4.9 Inactive Loop Startup (UFSAR Section 15.2.6).
An analysis of the Inactive Loop Startup event from reduced power is provided in the UFSAR; however, the initial system configuration and conditions assamed in the analysis of the inactive loop startup event are pret.luded from occurrence by Technical Specifications.
The probability of occurrence or consequences of the event (both minimum DNBR and reactivity insertion due to boron dilution aspects) are, therefore, not af fected by the reduction in RCS flow rate associated with increased SGTP.
2.4.10 Spurious Operation of the Safety Injection System (UFSAR Section 15.2.14).
Spurious safety injection system operation at power could be caused by operator error or a false electrical actuating signal.
Following the actuation signal, the suction of the coolant charging pumps is diverted from the volume control tank to the refueling water storage tank.
The valves isolating the boron injection tank from the charging pumps and the 21
valves isolating the boron injection tank from the injection header then i
automatically open.
The charging pumps then force boric acid solution from the boron injection tank through the header and injection line, and into the cold legs of each loop. The low head safety injection pumps also start automatically but provide no flow when the reactor coolant system is at normal pressure.
The passive safety injection accumulator system also provides no flow at normal RCS pressure.
The analysis presented in the UFSAR reveals that the transient does not challenge the integrity. of the RCS, and that the transient DNBR remains above the initial value.
Although this is a non-limiting DNB event, the impact of a reduction in RCS flow rate due to increased SGTP on the DNBR results of the spurious safety injection analysis will be accommodated by a single penalty assessed against available retained DNBR margin. The development of this penalty is described in Section 2.2.
l 2.4.11 Small Break LOCA (UFSAR Section 15.3.1) l Analysis results for this transient have been demonstrated to be l
insensitive to marginal changes in RCS flow rate.
The effects of RCP operation for this transient have been conservatively incorporated into the Westinghouse evaluation model as described below.
Virginia Electric and Power Company employs the Westinghouse NOTRUMP Evaluation Model (12),(13) for analysis of this event.
The features of 22'
this model relating to reactor coolant pumps (RCPs) and flow comply with the requirements in 10 CFR 50, Appendix K, including the pump trip requirements of NRC Generic Letters83-10c and 83-10d (14). As described in Reference (13), the key evaluation model feature relating to pump modeling for small break LOCA is whether the pumps continue to run or are tripped early in the event. The specific pump steady-state flow rate is i
not a critical consideration in establishing conservative treatment of RCPs in the analysis.
The conclusions presented in Reference (13) indicata that the behavior of small break LOCAs with and without RCP operation which were established with the WFLASH model (15) are applicable 4
for analyses with NOTRUMP.
For the Appendix X analysis, it has been concluded that the conservative assumption is to assume that RCPs trip at the time of reactor trip due to loss of offsite power. The WFLASH RCP trip study (15) concluded that if the RCPs are tripped in accordance with Westinghouse Emergency Operating Procedure Guidelines, the system l
thermal / hydraulic behavior and calculated Peak Clad Temperature (PCT) will be almost identical to that obtained with the design analysis.
A reanalysis of the Emergency Core Cooling System (ECCS) performance for the postulated small break LOCA has been performed (23) in compliance with Appendix K to 10 CFR 50.
The results of this analysis are in compliance with 10 CFR 50.46, " Acceptance Criteria for Emergency-Core Cooling Systems for Light Water Reactors."
This analysis was performed with the NRC approved NOTRUMP code (12) of the Westinghouse LOCA-ECCS l
l evaluation model (13).
The thermal behavior of the fuel was analyzed l
using the LOCTA-IV code (24). The analytical techniques used are in full l
l 23 i
e
compliance with 10 CFR 50, Appendix K.
This analysis also includes several additional assumptions to provide margin in key input parameters.
The reanalysis concluded that the North Anna ECCS will be capable of mitigating the effects of a small break LOCA with a maximum FNAh of 1.60, at a rated thermal core power of 2893 MWt, for both 17x17 Standard and North Anna Improved Fuel products.
For the small break LOCA, the emergency core cooling system will thus meet the acceptance criteria as presented in 10 CFR 50.46.
These conclusions have been established for operation with steam generator tube plugging of up to 35* in any single steam generator.
This bounds the RCS conditions associated with the proposed flow reduction.
2.4.12 Minor Secondary System Pipe Breaks (UFSAR Section 15.3.2)
(UFSAR Section 15.2.14).
Section 15.3.2.1 of the North Anna UFSAR presents the description and results of the most recent evaluation of minor secondary system pipe breaks.
The section concludes that the analyses presented in Section 15.4.2.1 of the UFSAR (Main Steamline Break) demonstrate that the consequences of a minor secondary system pipe break are acceptable, since a DNBR less than the DNBR limit does not occur even for a larger secondary i
system pipe break.
The evaluation of the main steamline break event for the proposed reduction in the minimum measured RCS flow rate is presented in Section 2.4.19.
24
= __
i 2.4.13 Hisloaded Fuel Assembly (UFSAR Section 15.3.3) i Fuel and core loading errors, such as those that can arise from the inadvertent loading of one or more fuel assemblies into improper positions, loading a fuel rod during manufacture with one or more pellets of the wrong enrichment, or the loading of a full fuel assembly during manufacture with pellets of the wrong enrichment will lead to increased heat fluxes if the error results in placing fuel in core positions calling for fuel of lesser enrichment. Also included among possible core-loading errors is the inadvertent loading of one or more fuel assemblies requiring burnable poison rods into a new core without burnable poison rods.
The. UFSAR Section 15.3.3 analysis of the misloaded fuel assembly accident indicates that the consequences of this accident are limited either by administrative controls or operational actions in response to the detection of a misloaded assembly.
As such, no further evaluation is necessary to support operation with the reduced minimum measured RCS l
flow rate.
l l
l 25
2.4.14 Single Rod Withdrawal at Power (UFSAR Section 15.3.7)
The Single Rod Withdrawal at Power event produces a system transient response which is similar to the uncontrolled control bank assembly withdrawal; that is, it results in an increase in core heat flux and a mismatch between core power generation and power removal by the steam generators. This power mismatch, which persists until the steam generator pressure reaches the relief or safety valve setpoint, causes an increase in the primary coolant temperature.
The transient would result in a violation of the core thermal limits if not terminated by either manual or automatic action.
The impact of reduced RCS flow rate due to increased SGTP on the DNBR results of the Single Rod Withdrawal at Power analysis has been fully t
l l
accommodated by a single penalty assessed against available retained DNBR margin. The development of this penalty is described in Section 2.2.
l 26
2.4.15 Volume Control Tank Rupture (UFSAR Section 15.3.6)
The analysis of the volume control tank rupture is in no way affected by the proposed reduction in the minimum measured RCS flow rate since RCS i
volume and flow rate are not analysis input parameters for this event, 2.4.16 Waste Gas Decay Tank Rupture (UFSAR Section 15.3.5)
The analysis of the waste gas decay tank rupture is in no way affected by the proposed reduction in the minimum measured RCS flow rate since RCS volume and flow rate are not analysis input parameters for this event.
2.4.17 Fuel Handling Accident Outside Containment (UFSAR Section 15.4.5)
The analysis of fuel handling accidents outside containment is in no way affected by the proposed reduction in the minimum measured RCS flow rate since RCS volume and flow rate are not analysis input parameters fnr this event.
2.4.18 Fuel Handling Accident Inside Containment (UFSAR Section 15.4.7)
The analysis of fuel handling accidents inside containment is in no way affected by the proposed reduction 'in the minimum measured RCS flow 27
rate since RCS volume and flos rate are not analysis input parameters for this event.
2.4.19 Major Secondary System Pipe Ruptures (Main Steamline Break)
(UFSAR Section 15.4.2.1).
The steam release resulting from the rupture of a main steam -pipe removes energy from the reactor coolant system.and causes a reduction in RCS temperature and pressure. -In the presence of a negative moderator; temperature coefficient, the cooldown-results in a reduction of core shutdown margin. If the most reactive-rod cluster control assembly (RCCA) is assumed stuck in its fully withdrawn position after reactor trip, there is an' increased probability that the core will become critical and return to power. A return to power following a steam pipe rupture is a potential
-problem mainly because of the. high power peal.ing factors-associated with the stuck RCCA.
The core is ultimately shut-down by the boric acid injection delivered by the safety injection system.
The main steamline break (MSLB) ' analysis is ' performed to-demonstrate that there would be ne core damage due to the onset of DNB, and that the-energy release-to contginment does not cause failure of the containment structure.
Increased SGTP reduces the steam ge'nerator's. capacity to remove energy from the RCS.
The primary-ef fect on the RCS of a main steamline break -
l-is to decrease RCS. temperature-and pressure, and to increase core l power
-i
.(given~ an end-of-cycle negative moderator temperature coefficient).-
A-28.
reduced capacity to remove energy from the RCS due-to increased SGTP will tend to make the cooldewn due to MSLB less severe (i.e., behave like a smaller break size).
The calculated transient DNBR under conditions of increased steam generator tube plugging would be less limiting than the current licensing analysis.
In other words, if SGTP is increased but the current Technical Specifications minimum measured total RCS flow rate continues to be met, the predicted RCS cooldown and core power excursion will be less limiting than that of the currently applicable analysis.
Except for its impact on RCS flow rate, increased SGTP is considered to be an analysis benefit. Because the RCS cooldown associated with smaller steamline breaks is lower, the transient RCS pressure in smaller breaks is higher, and the transient safety injection flow is lower.
- However, despite the lower safety injection flows, the DNBR's of smaller steamline breaks are predicted to be less limiting than those of larger breaks.
MSLB statepoints are evaluated for each reload core design. The impact of reduced RCS flow rate due to increased SGTP on the DNBR results of the main steamline break analysis has been fully accommodated by a single penalty assessed against available retained DNBR margin.
As described in Section 2.1, the proposed minimum RCS flow rate for analyses with a deterministic treatment of uncertainties is 269,800 gpm, which represents a reduction of approximately 3% from the analysis assumed flow rate of 278,400 gpm.
Utilizing a bounding W-3 DNBR partial derivative at conditions associated with MSLB, the flow reduction translates into a 4.3%
l penalty to be assessed against available main steamline break analysis retained margin.
This penalty quantifies the incremental impact.on the transient analysis minimum DNBR without consideration for the dynamic 29
ef fects of the reduced RCS flow on transient behavior,- which would be insignificant.
2.4.20 Rupture of a Main Feedwater Pipe-(Main Feedline Break)
(UFSAR Section 15.4.2.2)
I A major feedwater line rupture is defined as a break in a feedwater-pipe large enough_ to prevent the addition of sufficient feedwater to the-steam generators to maintain! shell side : fluid inventory in the L steam.
generators.
If-the break is postulated <in-a feedline-between the check valve and the steam generator, fluid from the steam generator may also be discharged through the break. Further,-a break in this location could preclude the subsequent addition _of'auxil'iary fee",ater to the affected' steam. generator.
A bruk upstream of ' the: fer ali,e -check valve-would 3
af fect the nuclear steam supply system only as'a loss of feedwater. (See
-Section._2.5.2).
Depending upon the size of the bren and the plant operating conditions at the time _ of the break,--the _ break could cause either a reactor 1 coolant system cooldown (by : excessive-energy discharge ;through ' the break):-or a j
- reactor coolant? system heatup. Potential reactor coolant system cooldown
.resulting from a secondary - pipe rupture.is--evaluated ; in uFSAR. Section 115.4.2.1.
.(See Section 2.4.19.)' Therefore, f only the: reactor coolant system heatup effects are evaluated for a feedlineLruptyre.
30'
The const:quences of feedline ~ break events upstream of the feedline check valve are bounded in severity by the consequences of the loss of normal' feedwater event which has been reanalyzed-for the reduction in RCS flow rate associated with-extended SGTP as described in Section 2.5.2.
As described _in the following, the consequences of feedline break events for breaFs downstream-of the-chech valve-have been evaluated to assess 1
the impact of_ increased steam generator tube plugging.
The -key analysis acceptance-criterion is the minimum RCS subcuoling -
margin ' experienced during-the t' a n 49t.
For the existing analysis, the-
- subcooling margin is 36'F;- A sMy of-the. sensitivity of analysis results to changes in RCS flow rate and steam generator tube plugging levels was performed which indicated a total. reduction in subcooling margi.n of less than 10'F.
On the basis of these results-. it may be--concluded that.the.
proposed reduction in. minimum measured RCS flow rate associated.with increased SGTP is easily secommodated by available analysis margin.
'I 2.4.21 ' Control Rod Ejectia (UcSAR.'Section 15.4.6).
The control rod ejection transient-is'detined as the mechanical failure
- of a; control rod mechanism pressure housing, resulting-in' the ejection-of -at rod cluster control assembly Land drive ~ shot; -The consequence--of this mechanical' failure is a rapid reactivity' insertion' together with an adverse core power distribution, possibly-leading _ to localized fuel rod -
{
damage.
31-l
4 4
I The analysis methodology for the control' rod ejection accident is R
documented in Reference (16); the most recent. analysis is documented in-the UFSAR.
The Reference (16) Rod Ejection Topical Report presents' sensitivity.
data that is suitable for evaluating > the impact of_ the RCS flow rate-i -
reduction due to increased SGTP on the results of the current design basis rod ejection analysis.
Of particular interest is the sensitivity -to _a i
j:
5% reduction in RCS mass flow rate which shows a 2.0'F increase in' maximum centerline temperature, a 36*F increase in maximum cladding' temperature, and a 1.0 BTV/lbm increase in maximum fuel pelletfenthalpy. -Of'these changes, only the maximum cladding temperature increase can be considered significant.
When this. bounding sensitivity _ is applied; to' the most limiting maximum clad. temperature result (zero power case at end of l_ife),
a temperature increase from 2575'F' to.2611*F would be predicted.
This result -is well-below the 2700'F tem.narature at which clad embrittlement-is predicted to occur.
It is c:nciv:.edLthat the-proposed decreased RCS:-
flow rate does not cause'the r, sults of the' rod ejection. transient: to exceed their respective analysis criteria limits.
2.4.22 Steam Generator Tube Rupture.(UFSAR Section 15.4.3).
- The steam generator tube rupture: accident is ' defined as the. complete p
severance of. a single - steam generator tube. - The' accident is-assumed to i
take place at power, with the reactor coolant contaminated with fission products consistent with the coolant activity limits set-for.h int the Technical Specifications.
The accident-leads to 'an--increase in 32
.. ~
-,_-...u.
contamination of the secondary system due to leakage of radioactive coolant from the reactor coolant system.
In the event of a coincident loss of of f site power, or failure of the condenser dump system, discharge of activity to the atmosphere takes place via the steam generator safety and or power operated relief valves.
In analyzing the dose consequences of a SGTR, operator action is assumed to terminate the primary to secondary mass transfer due to the tube rupture within 30 minutes.
In addition, bounding values of key parameters affecting the calculated consequences are assumed.
The proposed reduction in RCS flow rate associated with increased SGTP will not adversely affect the operator's ability to respond to and effectively control a SGTR event; the calculated consequences of a SGTR will be unchanged.
2.4.23 Large Break LOCA (UFSAR Section 15.4.1).
A reanalysis of the large break LOCA was not performed to support the proposed reduction in the minimum measured RCS flow rate associated with increased SGTP at North Anna Unit 2.
As described below, analysis results for this transient have been demonstrated to be insensitive to marginal changes in RCS flow rate.
Sirginia Electric and Power Company employs the Westinghouse 1981 Evaluation Model with BA3H (17) and the 1981 Evaluation Model with BART (1) for analysis of this event.
The features of this model relating to reactor coolant pumps and flow comply with the requirements in 10 CFR 50, 33
a 1
[
i' i
Appendix K.
Section-I.C.6,
" Pump Modeling," states the general i-l requirement for a pump-model and the justification of-its flow i
characteristics.
In addition, -Section I.D.3, " Calculation of-Reflood i
l Rate for Pressurized Water Reactors," requires that primary system t
f coolant pumps shall be assumed to have locked impellers if this assumption i-leads to the maximum calculated cladding. temperature.
The Westinghouse-i.
j' evaluation model incorporates this assumption.
<l; l
f a
l These required evaluation model features tend to minimize the impact j-of variations: in' steady-state coolant pump flow upon - results for large l
break LOCA' analysis. ;The PCT impact-is essentially limited to the-effect
-upon steady-state coolant temperatures associated with the coolant pump
+
i.
1, flow.
Reduced-RCS :: flow rate _ will. also cause reduced core inlet t-
. temperature,-which for the purpose 'of LOCA analysis, is-analogous to a-l RCS Tavg reduction. Virginia Electric and Power Company; sensitivity data indicates that the _ inlet temperature. reduction: associated with 'the i
proposed RCS flow decrease would cause' PCT to increase by approximately-2'F.
This'. is considered insignificant-in-relation to the conservative
[
- effects obtained by use of the required pump features of Appendix K.. For
}
}
. the current North Anna Unit ~ 2 cassessment, -it - is concluded that the-existing analysis provides-ani assessment which remains conservative for
[
operation with-the proposed reduction _in-RCS flow rate.
L Theieffects-of increased SGTP upon-the large break LOCA results will-
~
- be assessed as.part of the safety: evaluation'for.the' operation.of Nort'h f-Anna Unit.2 with each reload core design, i
b-f 34 k
,-r e
~
~+-
-4,.--r,-v w rw
--m
-,,-rer---*-
%,.r
-*.www%-m, s we r
--e.
2.5
SUMMARY
OF REANALYZED ACCIDENTS This section provides descriptions of the reana' lyses performed for these transients which were determined to be potentially impacted by the ptoposeo educ ti o')
in minimum measured flow rate associated with increased SGTP.
These transients were analyzed and previously raported to the NRC in support of the Narth Anna 1 extended SGTP evalurcion (21).
The system transient portion of these analyses was performed using the Virginia Electric and Power Company RETRAN system transient analysis code single and double loop models (2),(3).
The models were modified to appropriately reflect the effects of reduced RCS flow rate associated with increased SGTP.
Specifically, RCS flow rates, steam generator tube heat transfer areas (outside and inside the tubes), SG tube metal volume (heat capacity), and SG tube side flow area were reduced to reflect plugging effects.
Steam generator secondary pressures were adjusted to be consistent with the data discussed in Section 2.1.
A summary of important analysis initial conditions and parameters is provided in Table 2.1-1.
J 35
{
2.5.1 Loss of External Load Reanalysis (UFSAR Section 15.2.7).
-The Loss of External Load' accident'has been reanalyzed to assess the impact of reduced minimum measured flow rate associated with increased ~
SGTP.
A discussion of the _ reanalysis-is' presented.in the = following sections.
2.5.1.1 Accident Description A loss of load event can result from loss of external electrical load or from a turbine trip. For either-case,=offsite power _is available for.
the continued operation of. plant components such as-_the reactor coolant-pumps.
In this analysis, the behavior of the unit is evaluated for a' complete loss of steam : load from full-- power without a direct reactor trip, primarily to show the adequacy of the pr_ essure-relieving devices'and also-
~to demonstrate core protection margins.
l-Among the UFSAR cases, - the-beginning of cycle- (B0C) with Pressure-Control Case-and the 800- without Pressure. Control 1-Case are thei limiting.
cases for DNB and overpressurization concerns, respectively. These_ cases have - been reanalyzed to1 determine the impact : of. : the' reduced : minimum
- measured -flow rate associated. with increased SGTPi on-the Loss 'of; Load accident.
l l
c
- 36 L
.... - -.... = -. - -.
- ~ - -
. _ _ ~ _
5
.:p 2.5.1.2 Method of Analysis l
l The complete load loss-event was reanalyzed with the RETRAN (2),(3) system transient analysis code. All assumptions were consistent with or
[
conservative with respect to those in the previously approved analysis (5),(6). A summary of key analysis' assumptions is presented in the l-following.
4 l
i 1.
Initial Operating Conditions - For the ONB-limited portion of this j
transient analysis, the. initial reactor power, temperature, and i
' pressure are assumed to be at their steady state, full power, _ nominal i
' values.
Allowances for calibration and instrument errors are-i-
incorporated into the DNBR limit value as described in References (4),
(6), and (5).
l The overpressure portion of : this transient is performed -by deterministic application of these. uncertainty values:-.2% on reactor i
- power, 4 ' F-in average RCS temperature, 30 psi in pressurizer pressure, and deterministic thermal design flow were assumed.
These assumptions result in the maximum power difference for.the load loss, and the minimum margin to core protection limits at the initiation
[.
of the accident.
L 2.
Moderator _ and Doppler Coefficients o f. Reactivity A bounding i
positive-moderator temperature coefficient is assumed for beginning of life (BOL) conditions.
The analysis.used appropriate values of BOL_. Doppler power coeffici_ent.
[
3.
Reactor - Control _ - From 1 the; standpoint of-the maximum - pressures.
i attained,.it;is-conservative _ to assume that the ' reactor is in manual control.
L 4.
Steam Release - No credit is taken for.the operation oftthe condenser steam dump. system or steam -generator _ power operated relief valves.
. The steam generator pressure rises to the~ safety valve _ setpoint', where steam release through safety valves 1-imits secondary steam pressure.
5.- Pressurizer-Spray and Power-0perated -Relief __ Valves - Two cases for both'the beginning and end of life were analyzed:
i
- ~
a.
Full; credit. is taken -for. the effect. of pressurizer spray" and-power-operated relief valves in reducing or; limiting the RCS pressure.
b.
No - credit L is taken for. the effect of pressurizer spray and:
. power operated relief. valves in reducing or limiting _ the RCS
-pressure, g
-37 A~ _
__.-.-,..,_.a._..-,_,,..a.
_. ~, _,. _..
p 1
6.
Pressurizer Safety Valves - Valves are assumed to relieve at 3% above i
the. Technical ' Specification lift setpoint in conjunction with :-3%
(-
-pressure accumulation, i
- 7. - Feedwater Flow: - For both the overpressure _ and DNB analyses, Emain l-feedwater flow to the steam generators is conservatively assumed to be lost early in the transient.
In actuality; the feedwater flow would continue until the RCS temperature dropped _ to well' below the initial-value. No credit is-taken for auxiliary feedwater flow since a stabilized plant condition will be reached-before auxiliary-j feedwater initiation is normally assumed _ to occur.
The auxiliary
~
feedwater flow would remove _ core decay heat following_ plant t
- stabilization.
i j
Reactor trip Lis actuated by the first reactor. protection _ system trip setpoint-reached,' with no credit taken for the direct reactor _ trip on the j'
. turbine trip.
.j
~
2.5.1.3 Results and Conclusions-
[
For the limiting _DNB case-(80C with pressure control), the calculated l
DNBR--increased throughout the transient from the initial value of 2.15.
' Peak RCS pressure in the - limiting pressure. case (80CEwithout pressure t
l control) is 2676 psia, which meets the acceptance criterion of 2750 psia.
Peak" main _-steam-pressure 1511166 psia, :which _.is within the--acceptance p
i-limit'of-1210-psia.
i --
2 The results.of the analysis support the conclusion'that-a totalLloss
of external _ electrical load (a) Lwithout a -direct or immediate reactor
~
7 l-trip, -(b) ~with' 3%. tolerance and - 3% : accumulationLPSV setpoint1modelling-p 1and (c) with increased steam generator tube plugg'ing presents no' hazard:
to the integrityof theireactor coolant system"or the main steam. system.
p
. Pressurizerl and main steam safety valves are adequate ' to maintain-the j
maximum' pressures within the design limits.
Furthermore, the -integrity -
f
- 38F a
=
m
-.m..
of the core is maintained by operation of the reactor protection system, i.e., the DNBR will be maintained above the limit value. Thus, there will be no cladding damage and no release of fission products to the reactor coolant system.
39
-. ~... _. - - -. -,
.... - ~...
L 2.5.2 Loss of Normal Feedwater (Loss of Offsite AC) Reanalysis i
(UFSAR Section 15.2.8/15.2.9).
4 The deterministic Loss of Normal Feedwater accident has been reanalyzed to assess the impact of reduced thermal design flow associated
' with increased SGTP. A description of the reanalysis is presented in the l
following sections.
l' 2.5.2.1 Accident Description-i A loss of normal feedwater (due.to pump failures, valve malfunctions, or loss of offsite AC power) results in a reduction in the' capability of the. _ secondary system to remove the _ heat generated ' in the reactor core.
If the reactor were not' tripped during the accident, core damage could occur from a loss of heat sink.
If an alternative supply ofs feedwater were not supplied to the plant, _ residual heat following reactor trip would-
' heat the primary system water to the-point where _ water ' relief from the:
e pressurizer occurs. _Significantiloss of water from theLreactor coolant system could conceivably lead to' core damage..Since_the plant is' tripped well Lbefore the steam. generator heat transfer capability 1 s reduced,'the i
primary: system variables-never approach a DNB" condition.
The following provide the necessary protection against a loss of normal feedwater:
T 1.
Reactor trip onglow-low water' 1evel in.any steam generator, or on water level-below the' AMSAC setpoint in two steam generators after a time: delay, providing permissive C-20~is satisfied.
140
..2..
f i(
4
'd 2.
Reactor trip' on low feedwater flow signal in any steam generator.
(This-signal is actually a _ steam /feedwater flow mismatch in j
coincidenceLwith low water level.)'
3.
Two motor-driven auxiliary feedwater pumps (capable of delivering at j
least 340 gpm each) that are-started on a.
Low-low level in any steam generator, l
b.
Trip of all main feedwater pumps, l_
c.
Any safety injection signal, i
d.
{_
e.
Manual actuation, l
f.
AMSAC actuation.
!=
4.
One turbine-driven auxiliary feedwater pump (capable of delivering
~
at least 700. gpm) which is started on the. same signals' a's _the motor-driven pumps.
h The motor-driven auxiliary feedwater_ pumps are supplied by the diesel generators if a loss of offsite power occurs; the turb_ine-driven pump uses
{
steam from the secondary system.
Both pump _ types are designed to start l
within one minute' even if a loss of' AC power occurs simultaneously with a loss of normal feedwater.
The auxiliary pumps take suction from the emergency-_ condensate _ storage tank for delivery to the steam generators.
l l
l The loss of ~ normal feedwater accident analysis. must demonstrate that the auxiliary feedwater _ system -is_ capable of _. removing the ' stored and L residual _ heat following -a loss'of normal.feedwater, and preventing:either overpressurization of. the reactor coolant system or. loss of water from -
L
- the reactor.-. coolant-. system.
The -'results iof the accident analysis.
~
L j
establish the minimum flow requirement for the auxiliary feedwater pumps.
L 41 w.-,,-
I' I
1 l
i 1
2.5.2.2 Method of Analysis 3-
}
l The complete loss of normal feedwater event was reanalyzed with the i
i RETRAN system transient analysis code (2),(3).
All assumptions were consistent'with or conservative with respect to those-in the previously_
I; approved-analysis- (18),(19) with the exception of the steam generator secondary side heat transfer coefficient modelling during the. time l
between loss of feedwater and initiation of auxiliary feedwater. Although j
the secondary. side heat transfer coefficients used were higher than.those v
associated. with the previously. assumed heat transfer mode of stagnated -
4
(
flow, pool boiling heat; transfer,.the heat transfer. coefficients used in s
i_
this' analysis. remain conservatively low with respect to the expected values for actual plant operating conditions.
The analysis assumed. the loss t
- of normal feedwater to all steam-j generators as the initiating event. _ Reactor trip was assumed to-occur:
p on low-low steam generator level. Auxiliary feedwater flow from two motor p
driven pumps was-initiated 60 seconds after the steam ' generator reaches
-the low-low level.
l l
For conservatism,- pressurizer and steam L generator power-operated relief' valves and - pressurizer pressure control' were assumed :to be
[
unavailable. The pressurizer high pressure,: pressurizer high level, and:
overtemperature/ overpower AT trips were' assumed not to function. 4 Reactor.
l:
coolant' system.. pressure, temperature,- power and - flow measurement:
l :-
uncertainties, 'and uncertainties in initial--pressurizer and steam generator levels were considered. Reactivity parameters were established L
42:
I
at values demonstrated to most adversely impact the transient analysis results.
Decay heat was assumed to be 1.2 times the 1971 ANS standard value.
Cases were analyzed both with offsite power assumed to be available and with offsite power unavailable.
2.5.2.3 Results Following termination of normal feedwater flow and reduction of heat transfer to the secondary side, reactor coolant system temperatures, pressurizer pressure and pressurizer liquid volume began to increase.
At approximately 30 seconds af ter loss of feedwater, the reactor and turbine tripped on low-low steam generator level; RCS temperatures and pressurizer pressure and liquid volume dropped rapidly due to the decrease in core power. RCS temperature and pressure continue to decrease, until 370 seconds into the transient, when the liquid inventory in the steam generator not receiving auxiliary feedwater has been discharged through the safety valves. With this reduction in the heat sink, temperature and pressure continued to rise until approximately 1000 seconds when the remaining liquid mass in the two remaining steam generators, along with the mass added by the auxiliary feedwater system, became sufficient to dissipate the stored energy of the RCS.
At approximately 2500 seconds, boiloff of liquid inventory in the two steam generators receiving feed had decreased such _that auxiliary feedwater flow was sufficient to just replenish liquid inventory discharged through the-safety valves.
RCS temperatures and pressurizer pressure and liquid volume increased until approximately 5100 seconds, 43
i i
l at which time the decay heat generation was finally matched by the heat-removal of the auxiliary feedwater flow.
Temperature, pressure, and b
liquid volume-decrease for the remainder of the transient. A maximum RCS L
temperature of 598'F, a maximum pressurizer pressure of 2570 psia, and-a 2
3 maximum pressurizer liquid volume of 1050 f t were attained in the most i
limiting case.
i-i The results of the case in which offsite power is not available are i
less 1_imiting-than the results of the"cass with offsite power.
ThisLis l
expected, since -the case -with offsite power ! available also assumes
{
continuous operation -'of the reactor coolant pumps, which contribute additional energy to the RCS for removal through~the steam generators.
4 2.5.2.4, Conclusions 1
i The UFSAR Section 15.2.8/15.2.9 loss of normal feedwater events were reanalyzed to eva_luate the impact of reduced thermal f design - flowirate -
l associated = with -increased steam - generator tube -plugging --~on analysis results. _The analyses-demonstrated that. increased steam generator tube plugging Llevels do not-adversely impact the - ability._ of. the auxiliary -
feedwater system-to deliver. adequate _feedwater-to-prevent'the_ relief-of rea'ctor coolant water through the-' pressurizerc relief or safety _ valves, andto(preventsystemoverpressurization. For both the case.with offsite
- power assumed to be available and.with.offsite power" unavailable, the L
feedwater flow - rates ' required - to provide adequate ' cooling werel L
demonstrated to be well below actual deliverable pump flow rates.
44-i.._
r t
1 2.5.3 Rod Bank Withdrawal at Power Reanalysis (UFSAR Section 15.2.2).
i The Rod Withdrawal at Power Accident has been reanalyzed to assess the l
impact of reduced minimum measured flow rate associated with increased SGTP. A-statistical treatment of key-analysis uncertainties was utilized in accordance with North Anna-implementation of the methodology described in References (4),(5), and (6). A discussion of the analysis is presented-in the-.following sections ~.
-2.5.3.1 Accident / Description The uncontrolled rod cluster control assembly - (RCCA) withdrawal at-power is a postulated Condition 11 event initiated by' operator action or control system malfunction. The transient is characteri_ zed by an increase i_n _ core heat flux resulting in a mismatch between-core-power generation -
and power removal-by the steam generator.
This power mismatch, which persists until-the steam: generator pressure reaches the-relief or safety-valve setpoint, causes. an increase' in.the - primary coolant temperature.
The transient would result in violation of the core thermal limits if not terminated by either manual or automatic action. - The reactor. protection system is' designedL to terminate the transient prior. to exceeding core L
-thermal ~ limits.
l-The Rod Withdrawal at Power (RWAP) event' is used-to: verify that the Overtemperature :aT protection ~ setpoints perform successfully under-postulated transient conditions.
The cCculated setpoints are input ~in
.45
.=-
-, ~.. -,
the RWAP transient analysis and are successfully verified if all transient results meet the DNBR limit.
The RWAP event is used since its analysis covers a wide range of plant initial and transient conditions representative of the events which rely upon Overtemperature AT for core protection.
2.5.3.2 Method of Analysis The rod withdrawal at power event was reanalyzed with the RETRAN s
(2),(3) system transient an lysis code. All assumptions were consistent with or conservative with respect to those in the previously approved analyses (6),(5). The RETRAN code provided transient pressures, core inlet temperatures, heat fluxes, and core flows which were used as input to a detailed thermal / hydraulic statepoint analysis using the COBRA (20) code. The WRB-1 correlation (7),(8) was used.
To fully evaluate the RWAP event, a wide range of initial plant conditions are analyzed to determine those which are most limiting.
Permutations of the following conditions were analyzed:
1.
Initial NSSS power levels of 100, 60, and 10% with minimum feedback for a wide range of reactivity insertion rates.
2.
Initial NSSS power levels of 100, 60, and 10% with maximum feedback for a wide range of reactivity insertion rates.
It is assumed in the analysis that the steam dump and rod control i
systems do not function during the RWAP event. However, credit is taken 46
for pressurizer power-operated relief valves and s.afety valves, steam generator atmospheric relief valves and safety valves, as well as pressurizer spray (full flow from both valves is assumed).
2.5.3.3' Results and Conclusions The reanalysis of the rod withdrawal at power event demonstrated that the minimum DNBR will remain above the DNBR design limit for operation with reduced minimum measured flow associated with extended steam generator tube plugging. As described in Sections 2.2 and 2.3, a penalty has been extracted from Core Thermal Limit retained DNBR margin to ensure that the current Technical Specifications OTAT and OPAT reactm trip setpoints continue to provide bounding core thermal limit protection.
This analysis of the rod withdrawal at power event confirms that bounding Core Thermal Limit protection continues to be provided over a wide range of reactivity insertion rates and SGTP levels.
Figure 2.5.3-1, on the following page, presents the~ minimum'RWAP DNBR result as a function of reactivity insertion rate.
The upper graph (labelled 0% SGTP) is the analysis result assuming the current minimum measured flow.
The bottom graph (labelled 40% SGTP) is the result from the revised analysis with reduced minimum measured flow.
These results demonstrate that the combination of Overtemperature AT. and high flux reactor trips act together to provide core DNB protection.
47
Ef f set si tesetivity lasettles Aste es Misines OIBI free 1803 Fever, Minimes Feedbett 2.20-2.10-2.00-
=1.s0-og.ssTP E1.80-
=
- 1. 70-so-ns
431 SCTP 1.50-
[
em 1.50-1.40,
IE-01 1E+00 1E+41 IE+02 AEACT!YlTT IISEITIOR RATE (Ot/SEC) l l
l Figure 2.5.3.
2.5.4 Complete Loss of Flow Reanalysis (UFSAR Section 15.3.4).
The Loss of Flow Accident (LOFA) has been reanalyzed to determine the impact of reduced minimum measured flow rate associated with increased SGTP. A statistical treatment of key analysis uncertainties was utilized in accordance with North Anna implementation of the methodology described in References (4),(5), and (6). A discussion of the analysis is presented in the folicwing sections.
2.5.4.1 Accident Description A complete loss of forced rractor coolant flow may result from a simultaneous loss of electrical power to all three reactor coolant pumps.
If the reactor is at power at the time of the accident, the immediate effect of a LOFA is a rapid increase in the coolant temperature.
This increase could result in DNB with subequent fuel damage if the reactor is not promptly tripped.
Reactor protection is provided by either the pump underfrequency or undervoltage trip function.
2.5.4.2 Method of Analysis The LOFA was reanalyzed with the RETRAN transient analysis code (2),
(3). All assumptions were consistent with or conservative with respect to those in the previously approved analyses.
The RETRAN code provided transient pressure, core inlet temperature, heat flux, and core flow which were used as input to a detailed thermal / hydraulic statepoint analysis performed with the COBRA (20) code.
The WRB-1 correlation (7),(8) was 49
4 used. Two cases were analyzed: a complete loss of voltage at the RCP breakers and a 5.0 Hz/sec decay rate of the supply frequency (commonly referred to as the 'undervoltage' (UV) and 'underfrequency' (UF) cases, respectively).
A +6 pcm/'F moderator temperature coef ficient (MTC) was conservatively assumed although the actual full power MTC will be zero or negative. Delay times of 0.6 second and 1.2 seconds were assumed for the underfrequency and undervoltage trips, respectively, f
4 2.5.4.3 Results and Conclusions The underfrequency trip LOFA was found to be the more limiting event.
Transient DNBRs remained above the statistical DNBR design limit throughout the transient for both the UF and UV events.
Figures 2.5.4-1 through 2.5.4-4 on the following pages present the result of the most limiting complete loss of flow case (underfrequency). - Graphs of RCS flow, pressurizer pressure, normalized core average heat flux, and DNBR as a function of time are provided.
50
i one--r:-+== y case, acs new vs uma Uncerfrecuency Case - ACS Flow as a Function of Time 1.2 1
i h
J 1
0 s
'O U
t D
3.5
+
u e
O.4 c
9 l
\\
0.2 i
o oo
'o 2.0 a.o 4o s.n G.o o
..a s.o u
Time (seconcs) l l
i i
Figure 2.5.4-1 I
l l
Dasarfrequenay case, ECS Pressure vs Time Unoerfrecuency Case - PZR Presstre as a Function of' Time (Double Scray, 205 PORV StPt Reduction, No Hesters) 2Mo 23 3 m
t mo l-
.1 30 1
)
v s
itso 3
\\
2 3
22E L
3
)
1 E'
mo 4
/.
d
/
i
=
t mo 2240 mo 0.0 -
ta 2.c 3.0 4.0 5.0 s.0 7.0 s.0 3.s 2.s Time (Seconds):
Figure 2.5.4-2
I cadertrequenay case, seat Flux vs Time l
l MNumcy b - hli200 Hett Flux as a EurCflen of Time l
4.2 I
\\
r l
1 D
l 3.s l
I C
2 3.E
- J I
l N
9 E
34
\\
9 w
e
..s 0
0.0 10 2.0 3.0 40 5.0 6.0 7.0 0.0 9.0 m,g Time (Seconcs)
Figure 2.5.4-3
.... -... ~...
i k
4 Undertrastaansy case, Ilust vs fina
,1, we.eu =y ca
. men as a 5,wsion er ti i
)
/
i
/
j i
i m
/
1
'N
/
i N x, j
!i t i c
=>
t i
1 Underfrecruesey case, Iluna vs Tina - Enlariped view
~ -.
=
'a 1
i f
f l
\\
g..
I W
l ss < m,
i Figure 2.5.4-4
~ - - - ~ ~ ~
- - - ~ ~ ~ ' '
2.5.5 Locked Rotor / Sheared Shaft Reanalysis (UFSAR Section 15.4.4).
The deterministic Locked Rotor / Sheared Shaft accident has been reanalyzed to quantify effects of reduced thermal design flow rate associated with increased SGTP, A discussion of the analysis is presented in the following sections.
2.5.5.1 Accident Description The locked rotor event is defined as the instantaneous seizure of a reactor coolant pump rotor.
Flow through the affected reactor coolant loop is rapidly reduced, leading to a reactor trip on low flow signal.
Following reactor trip, heat stored in the fuel rods continues to be transferred to the coolant causing the coolant to expand.
At the same time, heat transfer to the secondary side of the steam generators is reduced, first because the reduced flow results in~a decreased tube-side film coef ficient, and then because the reactor coolant in the tubes cools down while the shell-side temperature increases.
Turbine steam flow is reduced to zero upon plant trip.
fhe rapid expansion of the coolant in the reactor core, combined with the reduced heat transfer in the steam generators, causes an insurge into the pressurizer and a pressure increase throughout the reactor coolant' system. The insurge into the pressurizer (a) compresses the steam volume, (b) actuates.the automatic spray system, (c) opens the power-operated relief valves, and (d)_ opens the pressurizer-safety valves. The two power-operated relief valves (PORVs) are designed for reliable operation and would be expected to function properly during 55 l
I-i
,I the accident.
However, for conservatism, the pressure reducing effect 1I of pressurizer PORVs and spray are not considered in the overpressure-1 l-portion of the analysis.
1 1
2.5.5.2 Method of Analysis 1
l The locked rotor / sheared shaft event' was_ reanalyzed with the RETRAN i
system transient analysis code (2),(3). All assumptions-were consistent-l-
with or conservative with respect to those in the currently-applicable analysis.
Previous-analyses-have-shown.that the results of the sheared-4 shaft event are bounded by those of the locked-rotor event.
Therefore, only_the locked rotor case is considered here.
4 l
The _ single reactor coolant pump. locked rotor incident-.is analyzed in i.
two _ parts.
First, a - peak pressure calculation is performed using l-conservative assumptions that tend to maximize the heat transfer from the
?
fuel to the coolant.
This calculation-' assumes.that the fuel rods in the
{
core do not experience departure from. nucleate boiling (DNB). - Second, ii.
the calculation is repeated'to provide a conservativeJassessment of the-f=
7
- fraction'of the core experiencing DNB.. The:doseLassessment is performed
[
by conservatively assuming that if-~a -rod experiences DNB, its cladding fails.
The fraction of rods which are predicted -tol experience = DNB is
{-
determined by an evaluation of FAH"versus fraction of fuel rods for each p
[
l reload core. This-process verifies for each ~ reload core that the. assumed
(
. percentage of fuel rod. failure does not exceed. the value of - 13*. assumed S
in the currently. applicable offsite dose calculation (see-UFSAR' Section '
i-15.4.4.2.7).
e 56' e
s
,n,
, -,~-,,
~--,,,,.n
,n, am.
%.d,--
a,,,,:,-,-..,~~,.~.---,v.,-
.--,-+-,.,,---~,L.
2.5.5.3 Results and Conclusions For the peak pressure analysis case assuming 3% setpoint shift +3%
t accumulation for the pressurizer safety valve, the peak RCS pressure (cold leg of a loop with pumps intact) remained well withi.) the acceptance limit (110% of the RCS design pressure, or 2750 psia).
Therefore, the overpressure results remain acceptable.
Figure 2.5.5-1 on the following page presents the transient response of peak RCS. pressure for the single locked rotor case analyzed.
For the core DNB case, the results showed that the criterion of <13%
of fuel rods experiencing DNBRs less than the design limit continues to be met. Therefore, the current offsite dose consequence analysis for this event remains bounding.
i f
J 57
1 40% PLUGGING ANALYSIS 14CEED RCP ROTOR Cota LEG PREBEUR (3% TOL + ACCUM. MODEL)
.i m
l tm <\\
i 4
i i
na -\\
I I
i j=<
I l
1 e na -
m, i
t k
so.
l' I
t I
3 a
p g
Ius unus l'
Figure 2.5.5-1 n-
3.0 NSSS AIO BALANCE OF PLANT SYSTEMS AND COMPONENTS l
3.1 NSSS SYSTEMS Af0 COMPONENTS i
For the North ?.nna Unit 1 extended SGTP evaluation (21), Westinghouse Electric Corporation performed reviews of the following NSSS components and systems.
These reviews confirmed that operation within the proposed conditions remains in compliance with the applicable codes and standards.
Reactor Vessel and Internals Control Rod Drive Mechanisms Main Loop Isolation Valves Reactor Coolant Pump and Motor Pressurizer 4
Stean: Generator
- Auxilic v Systems Components (tanks.-valves, heat exchangers)
Fluid Systems Reactor Protection and Control Systems An assessment of the Unit 1 evaluations has ccnfirmed that the conclusions remain valid for the operating conditions associated with a 275,300 gpm RCS flow limit for Unit 2.
The key findings and summary of conclusions for each area are discussed below.
3.1.1 Reactor Vessel and Internals An evaluation was performed to document the effects of operation at the proposed conditions upon the reactor vessel structural and fatigue analysis.
It was concluded that such operation will have no effect upon the reactor vessel stress report.
59
Assessments were also performed for various aspects of vessel internals
- design, including pressure
- losses, bypass
- flow, fluid temperatures, hydraulic lift forces, and flow induced vibration.
It was concluded that the internals system performance would remain within the bounds determined in existing analyses for operation et the proposed conditions.
i 3.1.2 Control Rod Drive Mechanisms 1
1 The control rod drive mechanism-structural integrity was reviewed for operation at the proposed conditions.
This was performed by comparison with the original design parameters and determining the impact of the revised parameters on the applicible stress reports.
The operating j
conditions are bounded by the original design pressure and temperature ranges.
3.1.3 Main Loop Isolation Valves i
The loop isolation valve function and structural integrity were reviewed for operation at the proposed conditions.
The conditions were found to have no impact on valve pressure boundary integrity or on valve operation.-
Therefore, the valves continue to comply with all applicable standards, 60
_. = -.
4 i
3.1.4 Reactor Coolant Pump and Motor i
The coolant pump function and structural integrity have been reviented
{
for operation at the proposed conditions.
The RCP hydraulics evaluation using revised flow / head values was found to be acceptable. The structural evaluation, which compared the new operating parameters to the original j
design specifications, concluded that the pump operating conditions are bounded by the original design pressure and temperature ranges. Revised electrical loads were calculated for the pump motors for each of three limiting design conditions.
No adverse impacts were found which would prevent the pump motor from performing its safety related function, i.e.,
1 coastdown.
4 e
3.1.5 Pressurizer The pressurizer equipment specification and stress report have been evaluated for operation at the proposed conditions.
The evaluation demonstrated that the operating and transient conditions are enveloped bu 'e generic transients used in the analysis of the pressurizer components.
Therefore, the existing stress report remains applicaSle.
3.1.6 Steam Generator The steam generator conditions under the proposed operation have been.
d evaluated for effects on thermal and hydraulic performance, U-bend vibration, and structural integrity. A range of conditions corresponding to the reduced RCS flow rate and various levels of extended SGTP were 61
evaluated.
Specific dcsign attributes studied were moisture carryovu,
hydraulic stability, U-bend vibration, and structural integrity of key l
components.
The results of these evalustions indicate that all steam generator design aspects continue to comply with all appilcable acceptance criteria for peration within the range of proposed conditions.
3.1.7 Auxiliary Systems Components (tanks, valves, heat exchangers)
Operation at the proposed conditions remains within the bounds of parameters assumed in the existing analyses for these components.
Therefore, there is no effect upon the auxiliary NSSS equipment.
3.1.8 Fluid Systems Review of the Reactor Coolant, Residual Heat Removal, Chemical and Volume Control and Safety Injection sptems were performed to confirm that operation at the proposed conditions remains in-compliance with applicable acceptance criteria.
It was concluded that each system continues to meet required acceptance c.iteria.
3.1.9 Reactor Protection and Control Systems An evaluation was performed to assess the impact of reduced minimum measured flow rate associated with extended SGTP upon. operation of the reactor control and protection systems.
It was concluded that operation j
at the propcsed conditions will require no changes _in nominal control or i
62
}
4 i
protection actuation setpoints and that each system will continue to perform its required functions.
4 n
(
k I
k i
63
3.2 BALANCE OF PLANT SETEMS AND COMPONENTS Previously, Stone and Webster Engineering Corporation (SVEC) evaluated the effects of operating North Anna Unit I with reduced RCS flow rate and extended SGTP upon the balance of plant systems and components.
The changes of significance for this assessment involve reductions in RCS flow, RCS volume, steam temperature, and steam pressure.
Engineering evaluations have been performed to demonstrate that these parameter changes and resulting effects on plant systems and components will be bounded by existing analyses and will continue to meet applicable design criteria.
These major balance of plant design areas were evaluated:
- Accident Analyses
- Balance of Plant (80P) Systems and Components
- Class 1 Piping
- Electrical Distribution System An assessment of the Unit 1 evaluations has confirmed that the conclusions remain valid for the operating conditions associated with a 275,300 gpm RCS flow rate limit for Unit 2.
The key findings and summary of conclusions for each area are discussed below.
3.2.1 Accident Analyses The loss of coolant accident is the design basis event which is analyzed to confirm several aspects of containment and safeguards system design.
Existing analyses for peak containment pressure, containment depressurization time, and net positive ~ suction head (NPSH) for spray and 64
safety injection pumps were evalusted for operation under the proposed RCS conditions. Analyses of postulated breaks of various RCS branch lines in the reactor cavity, steam generator cubicle, and pressurizer cubicle were also reviewed for the proposed conditions.
The results of the assessment concluded that the existing analyser vill remain bounding for d
operation at the proposed conditions.
3.2.2 Balance of Plant (80P) Systems and Components i
i A revised plant heat balance was prepared to reflect the proposed conditions.
The BOP systems were reviewed utilizing the heat balance to determine any effects on system operation, flow, pressure, temperature and heat load. The systems which were reviewed are listed below.
- Main Steam System
- Extraction Steam System
- Auxiliary Steam System
- Condensate System
- Feedwater System l
- Component Coolirq System
- Service Water System
- Auxiliary Feedwater System
- Bearing Cooling System
- Moisture Separator /High Pressure Heater Drains
- Low Pressure Heater Drains
- Steam Generator Blowdown For each system, the proposed conditions were assessed by comparison j
vith the design conditions incorporated into the existing analysis of l
system design. It'vas concluded that operation at the proposed conditions i
will remain bounded by existing analyses.of the 80P systems and 6S r
components, and each will continue to perform its design function in l
accordance with applicable acceptance criteria.
3.2.3 Class I Piping l
i The review of pipe stress and support analyses addressed the effects I
of the proposed conditions < n Re loop piping deflection profiles.
The aspects of interest are changes in end displacement boundary conditions for primary and secondary side branch piping and changes in UF.SAR design margins for equipment supports.
At the proposed conditions, it was concluded that the resulting changes are within the envelope of current normal operating temperatures for which the piping has been designed.
3.2.4 Electrical Distribution System Potential impact of operation at the proposed conditions was assessed for key plant electrical distribution system components.
No adverse effects were identified which would prevent these components from performing their design functions.
I 66
4 i
4.0 CONCLUSION
S i
A review of the accident analysis presented in UFSAR Chapter 15 has demonstrated that a reduction in minimum measured flow rate for North Anna Unit 2 to 275,300 gpm is accommodated by current analysis margins or by the assessment of a penalty against available retained DNBR margin for all accidents.
Explicit reanalyses were performed for the following
)
events to confirm the adequacy of current analysis margins:
3
- Loss of Normal Feedwater
- Loss of External Electrical Load
- Uncontrolled Control Rod Bank Withdrawal at Power
- Complete Loss of Reactor Coolant Flow
- Locked Reactor Coolant Pump Rotor i
The analyses showed that all of the acceptance criteria previously established in the UFSAR continue to be met for each reanalyzed event.
This conclusion will be reinforced by continued verification that core physics characteristics for operation with a reduced RCS flow rate J
- associated remain within the envelope established by the current reload safety evaluation.
The ciarrent Engineered Safety Features and Reactor Protection System setpoints set forth in the Unit 2 Technical Specifications have been demonstrated to provide adequate plant protection at the reduced flow rate condition. The current Core Thermal Limits have been verified to remain
- bounding for operation with the new RCS flow rate.
67
l i
l A review of the NSSS design transients, NSSS fluid and control systems, a
reactor control and protection
- systems, NSSS primary components i
i (including thermal and structural effects),
and steam generator I
I thermal / hydraulic performance has been performed.
It was concluded that I
NSSS systems and components will continue to meet applicable acceptance I
l criteria for operation with the ra uced design flow rates and the s
associated steam generator tube plugging levels.
An engineering evalu3 tion his also been performed to assess the impact
)
of reduced flow rate and extended tub plugging on the existing co.,tainment integrity analyses (including the impact on Net Positive Suction Head (NPSH) of engineered safeguards pumps) arid containment subcompart. nt integrity analyses. The existing analyses were shown to remain bounding.
A balance of plant systems review shows continued accep'.abl e performance under the reduced RCS flow rate and extended tube plugging condition.
1
[.
l l
l 68
REFERENCES (1) WCAP-9561-P-A, Addendum 3, Rev. 1, "BART A-1: A Computer Code for the Best Estimate Analysis of Reflood Transient - Special Report:
Thimble Modeling in Westinghouse ECCS Evaluation Model," July, 1986.
(2) Smith, N "VEPC0 Reactor System Transient Analysis using the RETRAN Loepute-Code," Topical Report VEP-FRD-41A, dated May, 1985.
(3) Letter from W. L. Stewart (Virginia Power) to H. R. Denton (NRC),
"Surry and North Anna Power Stations Reactor System Transient Analyses," Serial No.85-753, dated November 19, 1985 (RETRAN02 M00003).
(4) R. C. Anderson:
" Statistical DNBR Evaluation Methodology,"
Topical Report VEP-NE-2-A, dated June, 1987.
(5) Letter from W. L. Stewart to USNRC, " Virginia Electric and Power Company; North Anna Power Station Units 1 and 2; Proposed Technical Specifications Change," Letter Serial No.87-231, dated June 17, 1987.
(6) Letter from L. B. Engle to W. R. Cartwright, " North Anna Units 1 and 2 - Approval of Continued Use of Negative Moderator Coefficient for NA-1 and 1ssuance of Amendment for NA-2,"
(Letter Serial No.89-498), dated June 30, 1989.
(7) R. C. Anderson and N. P. Wolfhope, " Qualification of the WRB-1 CHF Correlation in the Virginia Power COBRA Code," Topical Report VEP-NE-3, dated November, 1986.
(8) Letter from G. S. Lainas (NRC) to W. R. Cartwright (VA PWR), dated
, July 25, 1989, Surry Units 1 and 2, and North Anna Units 1 and 2; Use of Virginia Power Topical Report VEP-NE-3, " Qualification of WRB-1 CHF Correlation in the Virginia Power COBRA Code" (TAC Nos.
67363, 67364, 71071, and 71072).
(9) Letter from W. L. Stewart to NRC, " Virginia Electric and Power Company; North Anna Power Station Units 1 and 2; Proposed Technical Specifications Change," Letter Serial No.89-336, dated May 23, 1989, (10) WCAP-11394-P-A, " Methodology for the Analysis of the Dropped Rod Event," January 1990.
(11) WCAP-10297-P-A, " Dropped Rod Methodology for Negative Flux Rate Trip Plants," June 1983.
(12) Meyer, P. E.: "NOTRUMP, A Nodal Transient Small Break and General
'!etwork Code," WCAP-10079-P-A (August,1985).
69 l
(13) Lee, N., et al.: " Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code," WCAP-10054-P-A (August, 1985).
(14) Generic Letter 83-10c and 83-10d from D. B. Eisenhut, Director of Division of Licensing (NRC), February 8, 1983.
(15) " Analysis of Delayed Reactor Coolant Pump Trip During Small Loss of Coolant Accidents for Westingnouse Nuclear Steam Supply Systems," WCAP-9584, August 1979.
(16) J. G. Miller and J. O. Erb:
"VEPC0 Evaluation of the Control Rod Ejection Transient," Topical Report VEP-NFE-2-A, dated December, 1984.
(17) Bessplata, J.
J., et al.: "The 1981 Version of the Westinghouse ECCS Evaluation Model Using the BASH Code," WCAP-10266-P-A, Rev.
2, March 1987.
(18) Letter from W. L. Stewart to NRC, " Virginia Electric and Power Company; North Anna Power Station Units 1 and 2; Safety Evaluation of Steam Generator Downcomer Flow Resistance Plate Modification,"
Letter Serial No. 87-474C, dated September 25, 1987.
(19) letter from S. A. Varga to W. L. Stewart, "NRC Safety Evaluation for Steam Generator (SG) Downcomer Flow Resistance Plate (DFRP)
Installation and Resultant Increase in Steam Generator Tube Rupture (SGTR) Dose Rates; North Anna Power Station Units 1 and 2,"
(Letter Serial No.87-678), dated October 23, 1987.
(20) Sliz, F. W. and K. L. Basehore: "VEPC0 Reactor Core Thermal Hydraulic Analysis using the COBRA IIIc/MIT Computer Code,"
VEP-FRD-33-A (October, 1983).
(21) Letter from W. L. Stewart to NRC, " North Anna Power Station Unit 1; Proposed Technical Specification Change; Reduced Minimum RCS Flow Rate Limit to Support Increased Steam Generator Tube Plugging Level," Letter Serial No.92-018, dated January 8, 1992.
(22) Letter from L. B. Engle (NRC) to W. L. Stewart, " North Anna Unit 1 - Issuance. of Amendment Regarding Reduced Minimum Reactor Coolant System Flow Rate Limit," (Letter Serial No,92-167),
dated March 3, 1992.
(23) " North Anna Power Station Units 1 and 2 - Implementation of Extended SGTP Small Break LOCA Analysis," 10 CFR 50.59 Evaluation 92-SE-0T-002, dated January 21, 1992.
(24) Bordelon, F. M., et al. :
"LOCTA-IV Program:
Loss of Coolant Transient Analysis," WCAP-8301, June, 1974.
70
(25) Letter from W. L. Stewart to NRC, " North Anna Power Station Unit 1; Supplemental Information Regarding Proposed Technical Specification Change for Reduced Minimum RCS Flow Rate Limit,"
Letter Serial No. 92-018A, dated January 31, 1992.
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Appendix !
DESCRIPTION OF RETAINED DNBR MARGIN ACCOUNTING METHDD The VRB-1 critical heat flux (CHF) correlation utilized by Virginia Electric and Power Company in the performance of DNBR analysis has a correlation DNBR limit of 1.17.
In deterministic DNBR analyses, key DNBR analysis parameter uncertainties are applied as transient analysis initial conditions in the direction which most adversely affects the DNBR.
Verifying that the DNBR remains above 1.17 throughout the transient ensures that the onset of DNB will not occur with a probability of 95%
and a confidence level of 95%.
By combining the key DNBR analysis parameter uncertainties with the WRB-1 correlation uncertainties in a statistical manner (rather than applying them as transient analysis initial conditions), a statistical DNBR limit of 1.26 was established. Transient analyses performed against this more restrictive limit are initiated from nominal values of key DNBR parameters, since the DNBR effect of uncertainties in these parameters is included in the statistical DNBR limit.
Verifying that the DNBR remains above 1.26 ensures that the onset of DNB will not occur with 95%
probability and confidence.
Virginia Electric and Power Company has chosen to perform safety analyses against a DNBR design limit of 1.46.
performance of safety analyses against this limit assures that the 1.26 statistical DNBR design limit would always be met, and that an additional (1.46-1.26)/1.46 = 13.7%
DNBR remains available to accommodate changes in plant operating conditions, or in detailed core thermal / hydraulic (T/H) analysis methods.
The percentage difference between the statistical DNBR limit and the design DNBR limit as calculated above has been termed " retained DNBR margin".
It is sometimes called " generic" retained DNBR margin, in reference to the fact that it can be used to account for the DNBR impact of changes in plant operating conditions or T/H analysis methods without regard to which specific transient analyses are affected by the changes.
In all cases, the 1.26 statistical DNBR limit continues to be met for all transients.
i Retained DNBR margin is a convenient vehicle for accommodating changes I
which affect many or all aspects of T/H design and safety analysis.
Penalties against retained margin totaling up to 13.7% DNBR may be accommodated without requiring across-the-board reanalyses of UFSnR transients.
Penalties are typically calculated by assessing the maximum perturbation of a DNB analysis parameter, such as flow or temperature, and multiplying this perturbation by a partial derivative representing the maximum predicted marginal change in DNBR per unit change in the DNB analysis parameter. The calculated penalty is arithmetically subtracted from available retained DNBR margin.
For example, with 13,7% available l
retained margin, a 3.7% penalty to accommodate effects of observed fuel rod bowing would leave 10.0% retained DNBR margin available for other penalties.
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It should be noted that the penalties arithmetically subtracted from the 13.7% available retained DNBR margin may vary from accident to accident. Accidents have been reanalyzed over time, and phenomena which were previously accounted for by a penalty against retained DNBR margin may have been explicitly modelled in the accident reanalyses.
The phenomena are then directly accounted for in the transient-specific DNBR result, and the penalty against retained DNBR margin need no longer be assessed.
For those transients which were identifi# as being impacted by the proposed reduction in the Total RCS Flow Rate limit, but which did not require reanalysis, a penalty was developed to be taken out of retained DNBR margin.
The penalty was developed by considering a range of statepoint conditions which bounded both normal operation and accident conditions, and by evaluating the DNBR impact of marginal changes in RCS flow rate. A partial derivative developed with the WRB-1 CHF correlation of 1.6% (percent change in DNBR per percent change in RCS flow) was determined to bound all-statepoints considered.
By multiplying this partial derivative by the proposed 3% change in Total RCS Flow Rate, a DNBR renalty of 4.8% DNBR was obtained.
The Main Steamline Break (MSLB) accident analysis utilizes the W-3 CHF correlation for DNBR calculations.
Because W-3 has a different DNBR sensitivity to marginal changes in flow, a separate penalty was developed to accommodate the effect of the proposed reduction in RCS flow rate on MSLB analysis results. This penalty was quantified at 4.3% DNBR, and will be assessed against available MSLB retained DNBR margin which was quantified in a manner analogous to that described previously.
Because the DNBR results of transient analyses do not typically approach the 1.46 design limit, there is seine amrunt of additional DNBR margin between the transient analysis minimum DNBJ result and the design DNBR limit. This margin has been termed " analysis DNBR margin." Analysis DNBR margin has not been used in any evaluation to justify the proposed reduction in minimum RCS flow rate.
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Appendix II APPROACH FOR ASSESSING THE UFSAR CHAPTER 15 ACCIDENTS The process of distinguishing those accidents requiring reanalysis from those which did not was essentially a screening process which subjected the individual accidents to the following tests:
1.
Is the accident impacted by neither RCS flow nor steam generator tube plugging?
In some cases (e.g., Waste Gas Decay Tank Rupture), the answer is no and thus the event need not be considered further.
2.
Is the accident impacted by plugging but not by flow?
These events (e.g.
Chemical and Volume Control System Malfunction, which is sensitive to RCS volume but not flow) will be addressed under 10 CFR 50 59 to support unit restart with extended plugging but have not been acnressed here since they are not impacted by the proposed RCS flow l
Technical Specification Change.
3.
Is the accicent lmpacted by RCS flow alone (i.e. and not by other tube plugging phenomena)? In some cases the dynamics of the event are not impacted by plugging effects, and the impact is limited to the direct effect of RCS flow on the DNBR.
An example is accidental depressurization of the reactor coolant system.
Accidents in this category were dispositioned via application of the generic DNBR penalty against retained DNBR margin.
4.
Is the accident potentially impacted by both RCS flow and steam generator tube plugging effects?
These are accidents which, in addition to the direct flow effect on DNBR, a.ay be sensitive to a.
steam generator hydraulic resistance (i.e., pressure drop) l
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b.
steam generator heat transfer area and/or secondary side initial l
conditions c.
reactor coolant system volume I
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instrumentation effects _(i.e., Overtemperature AT trip)
Accidents in this category were either explicitly reanalyzed (e.g.
Locked Reactor Coolant Pump Rotor, Loss of Normal Feedwater) or i
assessed using available sensitivity study results for the specific accident (as was done for the Main Feedline Break).
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- 10 CFR 50.92 i
NO - SIGNIFICANT HAZARDS CONSIDERATION EVALUATION 4
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10 CFR 50.92 No Significant Hazards Consideration Evaluation The proposed changes to the North Anna Power Station Unit 2 Technical Specifications have been evaluated against the criteria described in 10 CFR 50.92 and it has been determined that the proposed amendment to the operating license involves no significant hazards consideration. The basis for this determination is as follows:
As required by Technical Specifications 3.2.5 and 4.2.5.2, North Anna Unit 2 performs reactor coolant system (RCS) flow rate measurements once per fuel cycle.
The North Anna Unit 2 safety analyses are based in part on verifying, via the Technical Specifications surveillance, that the Reactor Coolant System total flow rate is greater than or equal to 284,000 gallons per minute (gpm).
Additional steam generator tube plugging increases the likelihood of violating this Technical Specifications requirement.
Therefore, safety analyses and evaluations have been performed which support an approximate 3% reduction in the RCS total flow rate limit to 275,300 gpm.
The proposed Technical Specifications changes implement a reduced total flow rate requirement which is intended to bound future measured flow values and any required steam generator tube plugging until steam generator replacement.
The changes will allow the unit to continue to operate with the expected increase in RCS loop resistance caused by increased steam generator tube plugging levels and ensure that the required safety margins for core cooling and accident analysis are maintained.
The safety evaluation provided with this change request documents a review of the accident analyses presented in the UFSAR. In summary, this review has demonstrated that a reduction in minimum measured flow rate for North Anna Unit 2 to 275,300 gpm is accommodated by current
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analysis margins or by the assessment of a penalty against available retained DNBR margin for all accidents.
Explicit reanalyses were I
performed for the following events to confirm the adequacy of current analysis margins:
Loss of Normal Feedwater Loss of External Electrical Load.
Uncontrolled Control Rod Bank Withdrawal at Power Complete Loss of Reactor Coolant Flow Locked Reactor Coolant Pump Rotor The analyses showed that all of the acceptance criteria previously established in the UFSAR continue to be met for each reanalyzed event.
This conclusion will be reinforced by continued verification that core physics characteristics for operation with a reduced RCS flow l
rate remain within the envelope established by the current reload l
safety evaluation.
I The current Engineered Safety Features and Reactor Protection System setpoints set forth in the Unit 2 Technical Specifications have i
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been demonstrated to provide adequate plant protection at the reduced J
flow rate randition.
The current Core Thermal Limits have been verified to remain bounding for operation with the reduced minimum RCS flow rate.
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A review of the Nuclear Steam Supply System (NSSS) design transients, NSSS fluid and control systems, reactor control and protection systems, NSSS primary components (including thermal and structural effects),
and steam generator thermal / hydraulic performance has been performed.
It was concluded that the NSSS systems and conponents will continue to meet applicable acceptance 1
criteria for operation with the reduced design flow rates and the associated steam generator tube plugging levels.
An engineering evaluation has also been performed to assess the 1
impact of reduced flow rate and the associated increase in tube plugging on the existing containment integrity analyses (including the impact on net positive suction head of the engineered safeguards pumps) and containment subcompartment integrity analyses.
The existing analyses were shown to remain bounding.
In addition, a balance of plant systems review shows continued acceptable performance under the reduced RCS flow rate and extended tube plugging condition.
Virginia Electric and Power Company has reviewed these proposed Technical Specifications changes relative to operation of North Anna Unit 2 with reduced minimum RCS total flow rate and determined that the proposed changes do not involve a
significant hazards consideration as defined in 10 CFR 50.92.
The basis for this determination is that this change:
a.
Does not involve a significant increase in the probability or consequences of an accident previously evaluated.
The impact of the reduced minimum measured RCS flow rate on operating characteristics, and accident analyses which support Unit 2 operation, have been fully assessed and documented in the safety evaluation.
The proposed reduction to the Technical Specifications minimum measured RCS flow rate does not impact either equipment or operating conditions that are considered in determining the probability of occurrence for any of the UFSAR Chapter 15 accident analyses.
The proposed reduction of minimum measured RCS flow rate has the potential to increase accident analysis consequences.
However, the results of.the reanalyses show that the design limits are met. Therefore, the consequences of an accident previously evaluated remain unchanged, b.
Does not create the possibility of a new or dif ferent kind of accident from any accident previously evaluated.-
The proposed change to the Technical Specifications does not-involve modifications to any of the existing equipment.
The
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impact of the proposed reduced minimum measured RCS flow rate on North Anna Unit 2 operating characteristics, and accident 3
i analyses which support Unit 2 operation, have been fully assessed and documented in the safety evaluation.
The proposed reduction to the Technical Specifications minimum measured RCS flow rate does not create any new or different accident initiators, so no unique accident possibility is created. Therefore, the proposed
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Technical Specifications changes would not create the possibility i
of a new or different kind of accident from any accident previously evaluated.
c.
Does not involve a significant reduction in a margin of safety.
The proposed amendment has been analyzed and the Technical 7
Specifications continue to ensure that adequate reactor coolant system total flow is maintained.
The impact of the propoced reduced minimum measured RCS flow rate on North Anna Unit 2 operating characteristics, and accident analyses which support Unit 2 operation, have been fully ass;ssed-and documented in the attached safety evaluation.
The analyses and equipment evaluations show that the applicable design limits are met.
Therefore, there is no significant reduction in the margin of safety.
t Based on the above significant hazards consideration I
evaluation, Virginia Electric and Power Company concludes that the activities associated with these proposed Technical Specifications changes satisfy the no significant hazards consideration standards of 10 CFR 50.92(c) and, accordingly, a
no significant hazards consideration finding is justified.
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