ML20136E877
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j NUCLEAR REGULATORY COMMISSION 2
WASHINGTON. D.C. 2066MWOI 2
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ATTACHMENT SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION I
RELATING TO REVISIONS IN THE TECHNICAL SPECIFICATIONS f(M THERMAL MARGIN AND RCS FLOW LIMITS FLORIDA POWER & LIGHT COMPANY ST. LUCIE UNIT I DOCKET NO. 50-335 1
INTRODUCTION By letter dated June 1,1996 (Ref 1), the Florida Power & Light Company (FPL) requested changes to the Technical Specifications (TSs) for the St. Lucie Unit 1 plant.
Based on safety analyses assumptions of 30% (average) of all steam generator tubes removed from service, the amendment proposes the following changes:
(1) the design reactor coolant system (RCS) flow rate is reduced from 355,000 gpm to 345,000 gpm, (2) the reactor core thermal margin safety limits shown in Figure 2.1-1 is
- revised, (3) the reactor coolant system total water and steam volume described in the design features is modified, (4) the Limiting Safety System Setting for the reactor coolant low flow trip function is reduced from 95% to 93 % of design reactor coolant flow, and (5)
TS 2.1.1 is modified to limit reactor power to 90% rated thermal power for Cycle 14 operation exceeding mid-cycle fuel burn up conditions.
The proposed changes to the TSs and Bases are as follows:
a.
Page 2-1, Specification 2.1.1, REACTOR CORE:
an asterisk is 9703130357 970301 PDR FOIA BINDER 96-485 PDR
__. _ _ _ -.. ~.. _. _. _ _. _ _ _ _. _ _ _ - _ _..... _ _ _ _ _ -
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j inserted following THERMAL POWER, and also t:.a following footnote is l
presented:
For Cycle 14 operation beyond 7000 EFPH, THERMAL POWER shall not exceed 90% of 2,700 Megawatts (thermal).
i 4
4 b.
Page 2-2, FIGURE 2.2-1, Reactor Core Thermal Margin Safety Limit-i Four Reactor Cooling Pumps Operating:
This figure is replaced in
[
its entirety with the revised FIGURE 2.1-1.
l The " vessel flow less measurement uncertainties" is changed from i
355,00 gpm to 345,000 gpm. The thermal limit lines have been revised to reflect the reduced flow.
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i c.
Page 2-4, TABLE 2.2-1, Reactor Protective Instrumentation Trip Setpoint Limits:
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(1)
For Reactor Coolant Flow-low FUNCTIONAL UNIT 3, for the TRIP l
SETPOINT and ALLOWABLE VALUES, has been changed from 95% of design reactor coolant flow with 4 pumps operating
- to 93%
of design reactor coolant flow with 4 pumps operating *.
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[
(2)
In Footnote *, the design reactor coolant flow with 4 pumps 4
operating has been changed from 355,000 gpm to 345,000 gpm.
4 d.
Page 3/4 2-14, TABLE 3.2-1, DN8 MARGIN:
the Reactor Coolant Flow
}
Rate has been changed from 355,000 gpm to 345,000 gpa.
e.
Page 5-5, DESIGN FEATURES, Specification 5.4.2: the description of the reactor coolant system VOLUME has been modified as an administrative changc'to read:
The total water and steam volume of the reactor coolant system is 3
11,100 i 180 cubic feet at a nominal Tavg of 567 *F, when not 3
accounting for steam generator tube plugging.
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3 2 BAuGROUND i
The current safety analyses for St. Lucie Unit I assume a minimum design RCS flow rate of 355,000 gpm and an average 25% (t 7%) of all steam generator tubes plugged (SGTP).
It is estimated that in the next refueling outage the number of steam generator tubes that will be removed from service (currently in excess of 2,000) will likely exceed the 25% (average) limit.
To conservatively accommodate the larger number of plugged SG tues, FPL proposed to change the TS to reflect the safety analysis assumption of 345,000 gpm minimum RCS design flow rate (based on 30% average of all steam generator tubes plugged), and proposed a change in the Reactor Protective System RCS Low Flow Limiting Safety System Setting from 95% to 93% of design reactor coolant fl ow.
The licensee has stated that the proposed changes affect the plant safety analyses in the following manner.
a.
A reduction in RCS flow rate has an adverse effect on the calculated-Departure from Nucleate Boiling Ratio (DNBR).
DNBR is a direct indication of available thermal margin, and a reduction in the calculated minimum DNBR indicates that thermal margin for the corresponding transient has been reduced.
b.
A reduction in the value of the low flow trip setpoint will result in a lower reactor core flow rate at the time of reactor trip, and can thereby impact the calculated minimum DNBR for certain transients.
c.
A reduction in RCS flow rate results in a corresponding increase in RCS average coolant temperature (Tave). A higher Tave can impact both DNBR-related and loss of primary inventory types of transients.
d.
The removal of additional steam generator tubes from service (plugging) reduces the primary to sec3ndary heat transfer area in the steam generators.
This effect is most relevant to transients
i 4
l involving a sudden reduction in the heat removal capability of the l
secondary plant.
In addition, a reduction of initial RCS inventory due to significant steam generator tube plugging (SGTP) can affect the results of boron dilution events, as well as the depth of core l-uncovery and calculated peak containment pressure resulting from j
loss of coolant accidents.
I i
3 EVALUATION j-The events in the St. Lucie Unit 1 Chapter 15 Updated Safety Analysis Report (UFSAR) were reviewed for Cycle 14 by FPL and Siemens Power Corporation-Nuclear Division (SPC) to assess the impact of an increase in SGTP to 30% 17%,
a reduced minimum Technical Specification RCS flow of 345,000 gps, and a reduced reactor coolant flow trip setpoint of 9313% of design flow (345,000 gpm). The licensee indicated that NRC approved computer codes (Refernces 2, 3 and 4) were used for the new supporting safety analyses.
The events identified that required reanalysis are: Loss of External Load (15.2.1), Loss of Normal Feedwater (15.2.7), Loss of Forced Reactor Coolant Flow (15.3.1),
CEA Misoperation (Dropped CEA Only) (15.4.3),_ Decrease of Boron Concentration (15.4.6), and Small Break LOCA- (15.6.5). All other events are either bounded by another event in the same category or are bounded by existing analyses of record.
3.1 UFSAR Chapter 15 events were reviewed in the following categories.
a.
Decrease in Secondary Side Heat Removal (15.2)
(1) Loss of External Load (LOEL) (15.2.7)
The Loss of External Load (LOEL) was identified as the limiting
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transient within this event category and reanalyzed to examine the impact of the proposed changes on the calculated maximum primary and secondary pressures.
Results of the re-analysis for this event indicated that the calculated peak primary pressure to be 2,714 psia, below the limiting criteria of 110% of design pressure
5 (2,750 psia).
Secondary system pressure was determined to be 1031 psia, which is less than the 1,100 psia secondary side acceptance criteria.
Therefore, it is concluded that increased steam generator tube plugging and the associated reduction in RCS flow, has no adverse impact.
b.
Decrease in Reactor Coolant System Flow Rate Events within this category of transients are initiated by a malfunction of the Reactor Coolant Pumps (RCP) with the resultant decrease in coolant flow causing a degradation of the calculated DNBR (closer to the limit of 1.22).
Two events in this category are impacted by the proposed reduction in design RCS flow and low flow trip setpoint: Loss of Reactor Coolant Flow (LOF) and Seized RCP Rotor.
(1) Loss of Reactor Coolant Flow (15.2.5)
The Loss of Flow (LOF) transient was evaluated with the initial conditions modified to include the proposed changes.
The objective of this evaluation was to determine whether the existing DNB-LC0 (TS 3/4.2.5), in conjunction with the RPS Low Flow Trip, will prevent the DNBR limit of 1.22 from being violated.
Results of this evaluation show a reduction in the minimum power margin from 6.8% to 1.9 % of rated power.
The available margin confirms that the minimum DNBR is greater than its limit value of 1.22.
Or, equivalently, the LOF event initiated within the existing DNB LCO constraints will not result in violation of the Specified Acceptable Fuel Design Limit (SAFDL) for DNBR.
Therefore, we find this to be acceptable.
(2) Seized RCP Rotor (15.3.4)
The seized rotor accident is assumed to be initiated by an instantaneous seizure of one of the reactor coolant pump shafts.
The margin available in this analysis, due to excess conservatism in
6 the reactor power and Radial Peaking Factor (Fr), has been determined to nearly offset the effects of the decreased coolant flow and reduced low flow trip setpoini., resulting in a net power penalty of 0.57%.
The small decrease in DNBR associated with the 0.57% power penalty will not cause the fuel rod failures to increase from the present value of 1% to more than 2.5% value used in the radiological analysis. Therefore, it is concluded that the impact of increased SGTP, reduced RCS flow, and reduced low flow trip setpoint on the fuel failure rate resulting from the Seized RCP Rotor accident is acceptable since the radiological consequence of this accident is bounded by the current analysis.
c.
Reactivity and Power Distribution Anomalies The events in this category are not impacted by the change in low flow trip setpoint except that the dropped CEA transient requires evaluation due to the reduced RCS flow.
(1) Dropped CEA (15.2.3)
The result of the evaluation performed, after accounting for the proposed changes, show a reduction in the minimum power margin from 8.0% to 4.6% of rated power.
Based on the available margin, it is concluded that the occurrence of a CEA drop event, after implementation of the proposed changes, will not result in violation of the DNBR SAFDL, provided the transient is initiated within the constraints of the DNB-LCO. We therefore find this acceptable.
(2) Uncontrolled CEA Withdrawal (15.2.1) l Roth the uncontrolled CEA withdrawal from low power and the CEA tthdrawal initiated from high power conditions are events analyzed against DNBR criteria.
The proposed reduction in RCS flow is expected to affect the DNB-related events in a similar manner.
Therefore, the CEA withdrawal event will continue to remain bounded l
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7 by'the Loss of Flow (LOF) transient.
Since the LOF analysis results were found to be acceptable, it-is concluded that the uncontrolled CEA withdrawal will not result in violation of the DN8R SAFDL, when initiated from within the DNB-LCO.
1 (3) Boron Dilution Event (15.2.4)
Protection against violation of SAFDL's for boron dilution events initiated at_ power is provided by the existing Thermal Margin / Low Pressure (TM/LP) trip, the Variable High Power Trip (VHPT) and the Local Power Density (LPD) LSSS.
Increased SG tube plugging will result in a small change in RCS fluid volume (~1.28%). This in turn will impact the time to criticality.ietermined in the boron dilution event analyses.
The reference analyses-for. dilution events initiated from hot standby or hot / cold shutdown conditions at St. Lucie Unit 1, show that margin exists to the acceptance criteria in the time to criticality. Since Mode 6 only considers the mass inventory in the reactor vessel, the increase in SG tube plugging does not affect Mode 6.
)
For Modes 2 to 4, the decrease in the RCS inventory was calculated to reduce the time to criticality from 72.02 minutes to 71.1 minutes. This time is greater than the acceptance criteria of 15 minutes. The time to criticality for Mode 5 is reduced from 20.54 minutes to 20.3 minutes, relative to the criteria of 15 minutes.
The baron dilution event results are, therefore, acceptable for the proposed changes.
)
(4) CEA Ejection Accidents (15.4.5)
A control rod ejection accident is defined as the mechanical failure of a control rod mechanism pressure housing resulting in the ejer' ion of a CEA and its drive shaft. The consequence of this mechanical failure is a rapid reactivity insertion and an adverse
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B core power distribution, which may result in localized fuel damage.
In Section 15.4.5 of the existing UFSAR licensing design basis, predictions of fuel failure are based on fuel centerline melt criteria (deposited energy in the fuel rod), not on DNBR criteria.
Therefore, a reduction in RCS flow proposed here, will not significantly impact the results of this event with respect to core damage or offsite radiological dose consequences.
d.
Decrease in Reactor Coolant Inventory Events (1) Large Break LOCA (LBLOCA) (15.4.1)
This event was evaluated to account for the impact of the proposed changes on the peak cladding temperature. A maxionum resinter density of 1.1% is used in the licensing analysis compared to the as-buuilt, resinter density for Cycle 14 of 0.81 %.
The use of an-j as-built resinter density is estimated to result in a reduction in initial fuel average temperature of 34 *F for the ' case of fuel stored energy near the begining-of-cycle (B0C) and at least 16 *F for the case of fuel stored energy representing the middle-of-cycle (MOC). This amount of conservatism in the fuel stored energy represents a significant conservatism in PCT, and is acceptable as the analysis of record would continue to remain bounding and meet the requirements of 10 CFR 50.46(b).
-(2) Small Break LOCA (SBLOCA) (15.3.1) i The Small Break LOCA event was evaluated for the impact of the reduced primary system flow and the increased SG tube plugging level (30% average).
The results of this event are influenced more by changes'to the top-peaked axial profiles. A review of Cycle 14 4
axial profiles showed that the maximum peak power elevation corresponding to the MOC was lower than that used in the analysis of record. The average burn up of the MOC axial profiles was 7000 i
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EFPH. The conservatism in the analysis due to this axial profile, up to this burn up, will offset any adverse effects due to the increased tube plugging and decreased RCS flow.
To operate beyond 7000 EFPH, the licensee conducted an evaluation to determine at what power they could operate to satisfy the S8LOCA criteria. Since SBLOCA is sensitive to core power, a reduction in power will effect peak fuel cladding temperatures during a SBLOCA, thus ensuring 10 CFR 50.46 conformity beyond 7000 EFPH for cycle 14.
The licensee is proposing to reduce power from 100% to 90% of rated power beyond 7000 EFPH.
This will provide sufficient margin to offset any adverse effects of the proposed changes. A teleconference between the NRC staff and the licensee staff assured the NRC staff that the analyses of record, namely the peak cladding temperature, would remain bounding at the 90% rated power operation.
The staff agrees with the derating of power for the St. Lucie's I
Cycle 14 operation beyond 7000 EFPH.
i (3) Inadvertent Opening of Pressurizer Pressure Relief Valves (15.2.12)
This event is bounded by the Loss of Flow event.
Since the proposed changes will not affect the relative behavior of DNBR between the two transients, this event will continue to remain bounded by the Loss of Flow event.
I The inadvertent PORV opening is also one of the transients used in the determination of the limiting pressure bias term in the TM/LP equation. This bias term is dependent on the maximum rate of change of DNBR experienced during the event, which for this case, is directly dependent on the rate of depressurization. Since the i
proposed changes do not affect the depressurization rate in this transient,'it is concluded that there is no impact on the existing TM/LP pressure bias.
-(4) Steam Generator Tube Rupture (SGTR) (15.4.4)
'b 2
10 ihe existing analyses have concluded that the associated radiological release is primarily dependent on the break flow rate and the corresponding primary-to-secondary mass transfer during the event.
The radiological releases were determined to be a small fraction of 10 CFR 100 limits.
The differential pressure across the steam generator tubes determines if flow through the break is choked or not.
The existing analysis or record examined the bounding case i
where break flow was choked before reactor scram. After reactor scram, the transient response is governed by the opening of steam dump and bypass valves.
The postulated increase in SG tube plugging level will result in reduced secondary side operating pressure at St. Lucie Unit 1.
This change could result in slightly longer times of choked flow for an actual SGTR.
However, the analysis of record assumes choked flow conditions during the period of interest before reactor scram, and therefore will remain bounding.
It is, therefore, concluded that the proposed changes will not alter the system response and the resultant potential offsite dose consequences for the SGTR event.
Increase in Heat Removal by the Secondary System (15.2.11) e.
Events in this category are evaluated by calculating the increase in primary system cooling due to the particular event initiator.
(1) Excess Load (15.2.11)
In the UFSAR three events with different initiators are postulated for the excess load event: 1) malfunction of the generator load limiter, 2) opening of the steam dump and bypass valves at power due to turbine trip permissive failure and 3) opening of the steam dump and bypass valves at hot standby due to controller =alfunction.
The limiting sub-event is the inadvertent opening of all the steam dump and bypass system valves at full power.
This scenario would cause an approximate 43.4% increase in steam mass flow rate, result rg in
-.-__.y 1
11 a decrease in reactor coolant temperature and pressure. Under these j
I conditions a negative moderator temperature coefficient of reactivity will cause an increase in core power.
The High Power
{
Level and Thermal Margin / Low Pressure (TM/LP) trips provide primary protection to prevent exceeding the DNBR limit during the full power excess load event.
In Section 15.2.11.3 of the UFSAR design licensing basis, this excess load event has been determined to be bounded by the Loss of Coolant Flow event for DNB considerations and none of the proposed changes will significantly impact the relative DNBR behavior in these two transients. Therefore, no reanalysis of this event was required.
(2) St2an; System Piping Failures (Inside/Outside Containment) (15.4.6)
Steam System Piping Failure events are analyzed to ensure that any fuel failure which might occur are limited to a small percentage of the fuel in the core.
These analyses are used to determine whether-fuel failures would result from violation of either the DNBR or fuel centerline melt SAFDL's.
The primary system cooldown following a limiting steam system piping failure initiated with increased steam generator tube plugging and reduced RCS flow will be bounded by (no more severe than) the existing analysis. The reduced primary to secondary heat transfer rate across the steam generator and the lower initial secondary pressure both contribute to make this a more benign event. Thesa effects ensure that the existing analysis of record for steam system piping failures will remain bounding and potential off-site dose consequences remain unchanged.
(3) Inadvertent Opening of a Steam Generator Relief (Atmospheric Dump)
Valve (15.2.11)
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.l 12 a
i This event is normally evaluated to assess radiological l
consequences.
Radiological releases caused by this event will be
[.
less severe and less likely to occur after implementation of the l-proposed changes because of the lower initial secondary side pressure resulting from the increased steam generator tube plugging level. The analysis of record assumes conservative Technical i
Specification limits for the primary to secondary leak which remains j
unchanged.
Therefore, the existing analysis of record will remain l
[
bounding for this event.
1 l
3.2 Impact of the Proposed Changes on Relevant Setpoint Analyses (15.6.5)
L ij' The impact of the proposed changes on relevant setpoint analyses was evaluated and verified to be acceptable. The setpoint analyses included the Reactor Protection System (RPS) Local Power Density (LPD) LSSS, LPD 1
Limiting Condition for Operation (LCO), Thermal Margin / Low Pressure (TM/LP) LSSS, and the DNB LCO for allowable core power as a function of l
Axial Shape Index (ASI).
i 3.3 Other selected UFSAR analyses that were evaluated included the following.
l l
a.
Plant Natural Circulation Capability (Appendix 5C) 1 j
FPL examined the increased tube plugging to determine if any adverse i
impact on natural circulation cooling capability would result.
FPL determined that the cooldown rate was dominated by operation of the secondary safety valves, and that increased SGTP had no adverse impact. We have reviewed the licensee's evaluation and agree with their assessment and have concluded that the proposed changes will not prevent the occurrence of natural circulation.
b.
Peak Containment Pressurization Following LBLOCA or Steam System Piping Failure (6.2)
Large Break LOCA and Steam Pipe Break inside of Containment analyses
_. _. ~ - - -.. - - -. -. -. _. _ -. - _.
13 of record were evaluated by FPL to determine if the reduced RCS flow and/or increased tube plugging level would cause the containment design pressure value to be exceeded.
For the LBLOCA event inside containment, the reduction in primary system fluid volume available for blowdown, a higher resistance to blowdown, and less secondary to primary heat transfer completely offset the effects from a slight increase in system energy due to j
the higher initial RCS Tave. The peak pressure in the analysis of record remains bounding.
Steam Piping Failures inside containment were also examined and it was concluded that, after allowing for the proposed changes, no compromise of the pressure limits on containment analysis would i
resul t.
Increased tube plugging will result in a small increase in the total secondary side mass inventory, but the overall energy stored in the fluid (and eventually released to containment during this event) is not increased.
In addition, the lower initial secondary pressure will allow less blowdown (from the intact SG) prior to Main Steam Isolation Signal (MSIS).
l c.
Auxiliary Feedwater System (AFW) High Energy Line Break (10.5.3)
The analysis for this event was evaluated with respect to the increased average primary coolant temperature.
It was determined that an additional 637 lbs of inventory would be boiled off from the secondary side reducing the dryout time from 650 seconds to 611.7 seconds. No credit was taken for the increased initial secondary side mass inventory (due to an increase in water density from a decrease in secondary side temperature).
From the analysis it was concluded that the acceptance criteria of more than 10 minutes (600 seconds) time for operator action to initiate AFW flow to avoid dryout is satisfied with increased steam generator tube plugging and reduced RCS flow.
i i
y
-a.
14 d.
Low Temperature Overpressure Protection (LTOP) Analysis (Appendix 4
4 581,5.2.2.6) j The existing LTOP analysis was evaluated to determine whether the postulated increase in steam generator tube plugging would. impact the consequences of startirg a RCP with the plant secondary side at a higher temperature than the primary.
Only a change in the RCP heat output or in the initial condition of primary to secondary AT could change the energy deposited in the primary system, and hence, the peak pressure.
Therefore, increasing the steam generator average tube plugging to 30% has no adverse impact on the. pressure spike caused by starting a RCP pump under low temperature conditions.
j l
I Overpressure Protection Analysis (Appendix SA) e.
The impact of the proposed increase in steam generator tube plugging j
and reduced RCS flow on the licensing analysis for the Loss of External Load event was previously discussed (Section 3.1.a).
Since that analysis confirmed compliance with the pressurization criteria, it indirectly verified the continued validity of the main steam safety valve sizing analysis of reference.
Therefore, it is concluded that the proposed changes do not require an increase in main steam safety valve capacity to satisfy the overpressuriztion criteria.
f.
Impact on Steam Generator Mechanical Load <.; (5.5)
The steam generator inlet temperature corresponding to 345,000 gpm RCS design flow (with 30% tube plugging) is calculated to be less than the acceptable value of 604 *F.
The temperature value of 604
'F was supported by the previous SG mechanical load calculations performed for the 25% 17% asymmetry tube plugging case. Therefore, there is no adverse impact on any acceptanca criteria for the tube
o c.
15 sheet and steam generator tube bundle, and sufficient margin to stress limits will remain available.
3.4 Summary FPL has performed the relevant UFSAR Chapter 15 safety analyses for the requested changes of reduced RCS flow and increased SGTP.
These changes have been found to be acceptable including the derate to 90%
rated thermal power for operation beyond 7000 EFPH in Cycle 14.
The reactor core thermal margin safety limits given in TS Figure 2.1-1 have been adjusted to account for the proposed value of design flow, define the areas of safe operation in terms of thermal power, RCS pressure, and cold leg temperature for which the DNBR is no less than the MDNBR limit.
The minimum DNBR limit for steady state operation, normal operational transients, and anticipated transients remains unchanged from the existing, approved value of 1.22.
The validity of Reactor Protective Instrumentation settings and trip functions in conjunction with related Limiting Conditions for Operation has been verified to provide assurance that reactor core design limits are not exceeded for the proposed change in RCS design flow.
The potential radiological consequences determined in the analyses of h record, and which demonstrate compliance with 10 CFR 100 acceptance criteria, remain bounding for operation with the reduced RCS flow and increased SGTP.
4 CONCLUSIONS Based on the evaluation in Section 3.0 above, the staff concludes that the licensee proposed revision to the Technical Specifications for the St. Lucie Unit 1 plant to allow a reduction in the required minimum RCS flow rate and RCS Low-flow rate trip are acceptable.
l, 1
16 1
The staff has concluded, based on the considerations discussed above that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation by operation in the proposed manner, and (2) l such activities will be conducted in compliance with the Commission's l
regulations, and issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public.
5 REFERENCE 1.
Letter from W. H. Bohlke, Florida Power & Light Company (FPL), to USNRC, June 1, 1996.
l 2.
XN-NF-81-58(A), Revision 2, and Supplements 1 through, "RODEX fuel Rod Thermal-Mechanical Response Evaluation Model," Exxon Nuclear Company, Revision 2 and Supplements 1 and 2 dated March 1984, Revision 2, Supplements 3 and 4 dated June 1990.
{l -
3.
XN-NF-74-5(A) Supplements I through 6 and Revision 2, " Description of-I the Exxon Nuclear Plant Transient Simulation Model Pressurized Water Reactors (PTS-PWR)," Exxon Nuclear Company, October 1986.
4.
XN-NF-75-21(A) Revision 2, "XCOBRA-IIIC: A Computer Code to Determine the Distribution of Coolant During Steady State and Transient Core Operation," Exxon Nuclear Company, January 1986.
i l
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. = -.-
July 2,1996 MEMORANDUM T0: Jon R. Johnson, Acting Director Division of Reactor Projects, RII FROM:
Frederick J. Hebdon, Director Project Directorate 11-3 Division of Reactor Projects I/II, NRR
SUBJECT:
TECHNICAL ASSISTANCE REQUEST (TIA 96-007) REGULATORY ACCEPTABILITY OF LUBRICATING VALVES PRIOR TO SURVEILLANCE TESTING (TAC NOS. M95274 AND M95275)
In a memorandum dated April 12, 1996, as a result of valve stroke timing practices at the St. Lucie Plants, you requested NRR assistance in evaluating the acceptability of lubricating valves prior to the performance of stroke time testing.
You also asked NRR to resolve a question as to whether the purpose 6f the stroke time testing was to demonstrate current and past operability of a valve, current and future operability of a valve, or both.
The Mechanical Engineering Branch (EMEB), NRR, has completed its review of these issues.
A discussion of these issues and NRR's response to your questions is contained in the attached memorandum dated June 24, 1996.
Docket Nos.:
50-335 and 50-389
Attachment:
As Stated cc w/ attachment:
R. Cooper, RI W. Axelson, RIII J. Dyer, RIV
Contact:
L. Wiens, NRR\\PDII-3 415-1495 Distribution
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/
St. Lucie Rdg.
DOCUMENT NAME:
G:\\STLUCIE\\TIA07. REY To receive a copy of this document, indicate in the box:
"C" - Copy without attachment / enclosure "E" - Copy with attachment / enclosure "N" - No copy 0FFICE PDII 3/LA E
PDil 3/Pn,,
i l B, PDII-3/D :)
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NAfE Sclayton /1AP LWiens E 4 W FNebdon H*
DATE 07/3 /96 ~
07/ F / R 07/1/M OFFICIAL RECIRD CtFY I
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1 NRC FILE CENTER CGPV
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June 24, 1996 j
~
MEMORANDLM 70:
Frederick J. Hebdon, Director Project Directorate 11-3 Division of Reactor Projects I/II FROM:
Richard H. Wessman, Chief Mechanical Engineering Branch i
Division of Engineering i
SUBJECT:
TECHNICAL ASSISTANCE REQUEST (TIA 96-007) 4 REGULATORY ACCEPTABILITY OF PRELUBRICATING VALVES (TAC Nos. M95274/M95275) i i
In a memorandum dated April 12, 1996, Ellis W. Merschoff, Director, Division of Reactor Projects, Region II, discussed the determination by Region II i
inspectors that the licensee of the St. Lucia nuclear power plant had l
lubricated a containment spray flow control valve prior to perfoming stroke time testing under Section XI of the ASME Boller & Pressure Vessel Code. The l
Region II inspectors considered this pre-lubrication to result in a nonrepresentative test of valve capabilities.
Region II requested the Office of Nuclear Reactor Regulation (NRR) staff to i
respond to specific questions on the acceptability of the licensee's actions in pre-lubricating valves prior to testing. Attached is our response to thoss j
questions.
l CONTACT:
T. Scarbrough, DE/EMEB 415-2794 i
Docket Nos.:
50-335 50-389 l
Attachment:
As stated 1
l cc w/ attachment:
J. T. Wiggins A. F. Gibson G. E. Grant i
T. P. Gwynn i
Distribution:
1 Central Files t
EME8 RF/CHRM i
LWiens i
RCreteau Valve List DOCUMENT NAME: G:\\SCARBROU\\RHWLUBE and PREC0W D fneIwe a capr of thfe escament, Indicete In the hos C=cepr u/o attachment /enetoeure E=Cary vtth attachment /enetoeure W = No espy 0FFICE ENE9"DC 6
EMEB:DE 3 E
t NAME TScaNrough RWessdb DATE d/896 f/24/96
/
0FFICIAL RECORD COPY ATTACHMENT
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,j-REGULATORY ACCEPTABILITY OF PRELU8RICATING VALVES PRIOR TO SURVEILLANCE TESTING (TIA 96-007) i Technical Assistance Raan=st In a memorandum dated April 12, 1996, Ellis W. Merschoff, Director, Division l
of Reactor Projects, Region II, discussed the detemination by Region II l
inspectors that the licensee of the St. Lucie nuclear power plant had lubricated a containment spray flow control valve prior to performing stroke-j i
time testing under Section XI of the ASME Boiler and Pressure Vessel (8&PV) i Code.
The Region II inspectors considered this pre-lubrication to result in a i
nonrepresentative test of valve capabilities. Therefore, Region II requested a response to the following questions:
l 1.
Is the practice of lubricating a valve prior to stroke-time testing acceptable under the regulations?
4 l
2.
Is the purpose of stroke-time testing under ASME Section XI to i
demonstrate the current and past operability of a valve, the current and future operability of a valve, or both?
i Evaluation l
The NRC regulations in 10 CFR 50.55a require that nuclear power plant i
licensees provide valves and pumps within the scope of Section XI of the ASME 8&PV Code with access to enable the performance of inservice testing of those valves and pumps for assessing operational readiness as set forth in i
Section XI of the ASME 8&PV Code. Criterion XI, " Test Control," of Appendix 8 to 10 CFR 50 requires that testing be performed under suitable environmental conditions. The current Inservice Testing (IST) Programs at St. Lucie Units I and 2 are based on the requirements of Section XI of the ASME B&PV Code,1986 Edition, with approved relief to certain requirements. Article IWV-1000 of ASME B&PV Code (1986 Edition),Section XI, states that it provides the rules and requirements for inservice testing to assess operational readiness of certain Class 1, 2, and 3 valves in nuclear power plants, which are required to perfom a specific function in shutting down a reactor to the cold shutdown condition, in mitigating the consequences of an accident, or in providing overpressure protection.
Subarticle IW-34I7 of the 1986 ASME B&PV Code states that, if a valve fails to exhibit the required change of valve stem or disk position or exceeds its specified limiting value of full-stroke time by this testing, the licensee shall initiate corrective action immediately with the valve declared inoperative if the condition is not corrected in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Generic Letter (GL) 89-04, " Guidance on Developing Acceptable Inservice Testing Programs," in Position 8 indicates that, rather than delaying 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the l'consee should make a decision on operability when the data is recognized as being within the required action range. GL 91-18, "Information to Licensees Regard <ng Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconfoming ATTACMENT
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Conditions and on Operability," provides siellar guidance on the timeliness of operability decisions based on test results.
IWV-3417 also requires that the test frequency be increased if a significantly longer stroke time is observed since the last test. Finally, IW-3417 requires that any abnomality or i
erratic action be reported. The St. Lucie IST Program Plan identifies no i
differences in interpretation of the NRC regulations or ASME Code when stating i
that the inservice testing in the plan is to be performed specifically to i
verify the operational readiness of pumps and valves which have a specific j
function in mitigating the consequences of an accident or in bringing the reactor to a safe shutdown.
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i More recent ASME codes and standards have repeated and amplified the l
importance of evaluating the operability of valves during inservice testing.
For example, Subsection ISTC, " Inservice Testing of Valves in Light-Water l
Reactor Power Plants," of the ASME Operation and Maintenance (ONc) Code states that it establishes requirements for inservice testing to assess the operational readiness of certain valves and pumps used in nuclear power plants. Subsection ISTC 4.2.9 requires that the valve be inundiately declared j
inoperable if the valve exceeds the limiting values of full stroke time.
Subsection ISTC 4.2.4 also requires that any abnonnality or erratic action be '
i recorded and that an evaluation be made regarding the need for corrective action.
l The NRC regulations, and ASME codes and standards, clearly indicate that the i
purpose of the inservice testing programs is to " assess" the operational readiness of the valves and pumps. Article IWA-9000 " Glossary," of ASME B&PV j
Code (1986 Edition),Section XI, defines " assess" as, determining "by evaluation of data compared with previously obtained data such as operating data or design specifications." More University Dictionary defines " assess" generally, Webster's II New Riverside as "to appraise or evaluate."
If maintenance is performed prior to inservice testing that ensures the capability of a valve or pump to operate properly, the licensee's IST program would be unable to evaluate the operational readiness of the component. This is reinforced by the requirement in the ASME Code that, if the stroke-time limits are exceeded, the condition be corrected or the valve be considered inoperable. The St. Lucie IST Program Plan intent "to verify the operational readiness" is more specific regarding the purpose of the. testing to determine the capability of the valves to perform their safety function.
The ASME Code recognizes that routine preventive maintenance will be performed by itcensees.
In some instances, this maintenance may occur shortly before a scheduled test required by a licensee's IST program. The effect of this maintenance on the validity of the test to assess operational readiness should be evaluated.
In Secties 3.5, " Testing in the As-Found Condition," of NUREG-1482 (April 1995), " Guidelines for Inservice Testing at Nuclear Power Plants," the staff stated that the Code does not specifically require testing to be performed for components in the as-found condition except for safety and relief valves, but does not define as-found even in the context of safety and relief valves.
In NUREG-1482, the staff noted its belief that most inservice testing is performed in a manner that generally represents the conditicn of a standby component if it were actuated in the event of an accident (i.e., no pre-conditioning prior to actuation).
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In NRC Information Notice 96-24 (April 25, 1996), " Preconditioning of Molded-Case Circuit Breakers Before Surveillance Testing," the staff stated that the
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practice of preconditioning molded-case circuit breakers (for example, by lubricating pivot points and manually cycling the breaker) defeats the purpose of the per' odic test.
i The staff stated that such preconditioning does not confirm continued operability between tests nor does it provide 'nfcrmation on j
the condition of the circuit breaker for trending purposes. The applicable licensee planned to revise its procedures before the next surveillance test to correct this situation.
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i In ASME Code Case QM-1, " Alternative Rules for Preservice and Inservice l
Testing of Certain Electric Motor Operated Valve Assemblies in LWR Power Plants (QM - Code - 1995 Edition; subsection ISTC)," the ASME provides an i
alternative to the stroke-time testing requirements of the GM Code to assess j
1 the operational readinoss of motor-operated valves (MOVs). The code case uses j
the same language as the NRC regulations and ASME Code in stating that j
inservice testing is intended to assess the operational readiness of valves.
l In implementing the code case, the licensee is required to determine the i
capability of the MOV during inservice testing.
The code case requires MOVs to be cycled at least every refueling cycle with diagnostic testing conducted-i on periodic intervals.
The code case allows grouping of MOVs with the j
infomation obtained from individual MOV tests applied to other MOVs in the group.
In Section 3.3, the code case specifically states that maintenance I
activities, such as stem lubrication, shall not be conducted if they might invalidate the as-found condition for inservice testing. The perfomance of i
maintenance prior to testing would defeat the ability to determine any degradation in the operation of the tested MDV and to apply the test results to other MOVs within the group. This code case is being endorsed (with certain limitations unrelated to preconditioning) for voluntary use by licensees in a forthcoming generic letter.
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In summary, the performance of maintenance on a component to ensure its proper operation prior to conducting a test negates the validity of the test in assessing the operational readiness of the component.
If the maintenance had
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not been performed, the component may not have been capable of performing its
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safety function. Clearly, the conduct of maintenance prevents the licensee from assessing if the component would perform as design, should it be called l
upon. Further, important information on trending of operating parameters for evaluating degradation would not be available.
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EMEB Resoonse 4
In response to the specific questions from Region II:
1.
The performance of maintenance that ensures the capability of a valve to satisfy the stroke-time test requirements of the ASME Code provides a false indication of the operational readiness of the valve. Therefore, a licensee activity to lubricate a valve prior to stroke-time testing for the principal purpose of satisfying ta test criteria at that specific time would not be considered to be within the intent of the NRC regulations under 10 CFR 50.55a or Appendix 8 to 10 CFR 50.
It is recognized that routine preventive maintenance, such as valve 3
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lubrication, might coincios occasionally with IST program testing.
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those cases, the effect of such maintenance needs to be evaluated to aasure that the ability to assess operational readiness of the valves and to trend degradation in the valve performance are not adversely affected.
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2.
The MC regulations, and ASME codes and standards, require licensees to establish IST programs to assess the operational readiness of certain
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valves and pumps.
If a valve fails its stroke-time test, the licensee is required to declare the valve inoperable. Therefore, the stroke-time i
j test is intended to demonstrate current operability. The licensee evaluates past operability since the previous stroke-time test based in part on the most current test results. The ASME Code prescribes comparison of stroke-time test data to previous test data so that licensees may obtain an indication that the valve should remain operable untti the next test.
It is recognized that the stroke-time test is i
limited in its effectiveness and, as a result, the ASME developed an alternative IST approach for MOVs in ASME Code Case OM-1.
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