ML19339A557
| ML19339A557 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 10/30/1980 |
| From: | Nichols T SOUTH CAROLINA ELECTRIC & GAS CO. |
| To: | Harold Denton Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8011040274 | |
| Download: ML19339A557 (20) | |
Text
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SOUTH CAROLINA ELECTRIC a gas COMPANY poseorncenoxre.
Cotums A, south CAnouMA 29218 T. C. NicHoLs, Jn.
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October 30, 1980 metsaa Onnano.s Mr. Harold R. Denton, Director Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, D. C. 20555
Subject:
Virgil C. Summer Nuclear Stati'.t Docket No. 50/395 Reactor Systems Branch Questions
Dear Mr. Denton:
In response to your letter dated 10/28/80, Sout'. Carolina Electric and Gas Company, acting for itself and agent for Scath Carolina Public Service Authority provides responses to questions issued by the reactor systems branch as a result of our meeting held in Bethesda on 10/8/80.
These vill be incorporated in the next FSAR ameniment.
It should be noted that the response to questions 211.129, 211.131 ind 211.132 will be pro-vided at a later date.
If you have any questions, please let us kaow.
Very truly yours, A
T. C. Nichols, Jr.
RBC:TCN:rh cc:
V. C. Summer G. H. Fischer T. C. Nichols, Jr.
E. H. Crews, Jr.
D. A. Nauman O. S. Bradham O. W. Dixon, Jr.
R. B. Clary W. A. 'Jilliams, Jr.
B. A. Bursey J. B. Knotts J. L. Skolds NFCF/Whitaker File THIS DOCUMENT CONTAINS POOR QUAUTY PAGES f
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211.124 Overpressurization of Reactor Vessel at Low Teriperature Pressure For protection of overpressurization of reactor vessel at low temperature and pressure you have provided spismically qualified.
nitrogen (N ) supply to each of tho PORVs which is sized to 2
assure that no operator action is required to terminate the transient in 10 minutes. Provide justification for this 10 minute limit and why it is enough for the operator to identify and terminate the cause of the transient.
RESPONSE
TVo pressurizer power operated relief valves have a seismically qualified supply of Nitrogen to their actuators.
In each line there is a 3.6 cubic foot tank where 660 psig nitr.ogeni is stored.
A 300 psig alarm (in the control room) is provided to alert the operator of low nitrogen header pressure. A regulator is pro-vided to reduce the pressure to 90 psig to the actuator. The tanks were sized for continuous valve cycling for 10 minutes where 480 cubic inches of nitrogen are used per valve cycle.
After this 10 minute period credit may be taken for the control room operator to take action necessary to terminate the over-pressurization event. Such actions may be the securing of a charging pump or reactor coolant pump.
By manual actuation on the main control board, nitrogen can be re-supplied to the header.
There are sufficient indicators available inside the control room for the operator to identify and terminate the event.
I
211.125.
. Identification of. Indicators.and Alarms Provided in the-y Control Room for Leakage Detection Provide a table of all indicators and alarms in the control. room associated with leak detection instru-mentation for all three types of leak detectors.
RESPONSE
The following is a tabulation of leak detection metho.Js '
inside the control room.
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LEAK DETECTION METHODS INSIDE CONTROL ROOM PRIMARY CONTROL ROOM
. PARAMETER DETECTION ELEMENT DISPLAY TYPE OF LEAKAGE Boron injector surge level switch alarm-high level reactor coolant leakage tank level (LS965) to'ECCS Refueling water storage level transmitters indication reactor coolant leakage tank level (LT990, LT991, LT992, alarm-high level to ECCS LT993) i accumulator level level transmitters indication reactor coolant leakage (LT920, LT922, LT924, alarm-high level to ECCS LT926, LT928, LT930) accumulator pressure pressure transmitters indication reactor coolant leakage (PT921, PT923, PT925, alarm-high level to ECCS PT927, PT929, PT931) reactor vessel flange temperature element indication leakage from reactor leak-of'f temperature (TE401) alarm-high temperature vessel
~
4 pressurizer safety. valve temperature elements indication reactor coolant leakage discharge temperature (TE463, TE465, TE467, alarm-high temperature to pressurizer relief TE469) tank i
pressurizer relief tank temperature element indication reactor coolant leakage temperature (TE471) alarm-high temperature to pressurizer relief tank' pressurizer relief tank level transmitters indication reactor enolant leakage level (LT470) alarm-high level-to pressurizer relief tank a
flow in pressurizer acoustic leak monitor alarm-high flow reactor coolant leakage relief line to pressurizer relief tank i
V U V
PRIMARY CONTROL ROOM PARAMETER DETECTION ELEMENT DISPLAY TYPE OF LEAKAGE leak detection drains level switches alarm-high level nuclear valve leak-off and miscellaneous equipment leakage steam generator radiation monitor indication primary to secondary blowdown and (RM-L3, RM-L10) alarm-high radiation system leakage sampling radiation main plant vent radiation monitor indication primary to secondary exhaust radiation (RM-A3) alarm-high rridiation system leakage turbine room sump radiation monitor iadication primary to secondary radiation (RM-L8) a.larm-high radiation system leakage component cooling radiation monitor indication intersystem leakage into water radiation (RM-L2A, RM-L2B) alarm-high radiation coaponent cooling water system component cooling temperature elements indication residual heat removal heat water temperature (TE7037, TW7047) alarm-high temperature exchanger leakage from RHR heat temperature switches exchanger (TS7038, TS7048) comp'onent' cooling water temperature elements indication reactor coolant drain tank-temperature from reactor (TE7118) alarm-high temperature heat exchanger leakage coolant drain tank component cooling water flow transmitters indication reactor coolant drain tank flow from reactor coolant (FT7116) heac exchanger leakage drain tank component cooling water temperature elements
~
indication reactor coolant pump therma 3 temperature from reactor (TE7140, TE7160, alarm-high temperature barrier leakage coolant pump' thermal TE7180) barrier component cooling water flow transmitters indication reactor coolant pump flow from reactor (FT7138, FT7158, thermal barrier leakage coolant pump therual FT7178) barrier
PRIMARY CONTROL ROOM PARAErER DETECTION ELEMENT DISPLAY TYPE OF LEAKAGE i
component cooling water temperature elements indication reactor coolant pump temperature from reactor (TE7128. TE7134, alarm-high temperature bearing leakage coolant pump bearings TE7148, TE7154, TE7168, TE7174) component cooling water flow transmitters indication reactor coolant pump flow from reactor (FT7126, FT7132, bearing leakage coolant pump bearbgs FT7146, FT7152 FT7166, FT7172) component. caelf os water temperature eament indication letdown heat exchanger-temper 4tiin rrca letdown (TE7196) alarm-high temperature leakage heat exchanger component cooling water flow transmitters indication letdown heat exchanger flow from letdown (FT7194) leakage heat'eitchanger 4
component cooling water temperature element indication real water heat exchanger alarm-high temperature imakage temperature from real (TE7188) l water heat exchanger componen't cooling water flow transmitter indication seal watec heat enhanger flow from real water (FT7186) leakage heat exchanger I
component cooling water temperature elements ind'ication RHR pump leakage temperature from kHR (TE7256, TE7246) alarm-high temperature i
pump seal component cooling water flow transmitters indication RHR pump leakage flow from RHR pump seal (PT7255, FT7246) auxiliary _ building sump level switch alarm-high level undetected leaks from level (LS7742) engineered safety feature systems in the auxiliary building 1
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PRIMARY CONTROL ROOM PARAMETERS DETECTION EL'EMENT DISPLAY TYPE OF LEAKAGE temperature senore alarm-high temperature undetected leakage from CVCS cuxiliary building ambient' temperature letdwon lines or auxiliary steam systems intermediate building level switches alarm-high level leakage from feedwater sump level (LS1950 thru LS1955) system i
RER pump room sump level switches alam-leakage grearer leakage in RHR pump rooms level (LS1966, LS1967 than 45 GPM LS1968) reactor building level transmitters indication leakage from systems inside sump level (LT1963, LT1964) alarm-high level the reactor building and leakage greater than 10 GPM incore instrument level senor alarm-leakage greater leakage around reactor sump level (LS1973, LS1974) than 1 GPM vessel a:d instrument chase
-leak detection sump level senor-alarm-leakage greater leakage from systems inside level (LS1961, LS1962) than 1 GPM reactor building I
condenser exhaust radiation monitor indication primary to secondary system radiation' (RM-A9) alarm-high radiation leakage 4
i reactor building air radiation monitor indication reactor coolant leakage sample radiation (RM-A2) alarm-high radiation I
testerature elements indication gross reactor coolant i
reactor building temperature (TE9201, TE9203) leakage
)
reactor building pressure transmitters indication gross reactor coolant l
pressure (PT950, PT951, PT952, leakage PT953 j
PRIMARY.
CONTROL ROOM PARAMETERS DETECTION ELEMENT DISPLAY,
TYPE OF LEMCAGE reactor building cooling flow switches alarm-flow greater reactor coolant leakage unit device flow (FS1900A, FS1900B) than 0.5 GPM NOTE: For a description of the above leak detection methods and other methods not directly indicated in the esntrol room, see FSAR Section 5.2.7, 7.6.5, 9.3.3, 11.4, 12.2.4 and questio.s.211.12 and 211.84.
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211.126
' Loss of CVCS or CCW to Reactor Coolant Pitmps or Motors In response to questions 211.123 concerning loss of CVCS or CCW to reactor. coolant pumps you stated that two RCP motors have been tested' with interrupted' CCW flow,. and that the test '
demonstrates that the'RCP motor can withstand loss of CCW flow' for'10 minutes'.without pump damage. Verify that the loss of CCW in both RCP motor bearings and the thermal barrier heat l
exchangers will not have a wo'rse effect' on' the RCP than the result of loss CCW to pump motor bearings only as simulated in your test.
Also, provide a summary of your pump test.
RESPONSE
The reactor coolant pump can continue to run following a' loss of cooling water to the thermal barrier provided that the pump seal temperature remains within allowable temperatures. This will be the case as long as seal injection is maintained.
j AIdditionally, since the loss of component cooling water to the 1
reactor' coolant pump does not, in itself, affect operation of l
the pump, a simultaneous loss of' cooling water to the thermal, barrier and the motor-bearing oil coolers is no worse than a loss of cooling water to th'e motor bearing oil coolers.
The test run by Westinghouse described in the response to Question 211.123 was applicable to the design used on the Virgil C. Summer Nuclear Station. A description of the test and results are provided in' response to Question 211.123 on page 211.123-9.
see the revised response to Question 211.123.
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Loss of Component Cooling Water
. )
Should a loss of CCW to the'RCPs occur, t'
chemical and volumel control system continues to provide seal injection flow to the RCPs; f
thesealinjectionflowissufficienttofpreventdamagetotheseals.
with a loss of thermal barrier cooling. Miovever, the loss of CCW ta
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the cio:or bearing oil coolers will result in an increase in oil temperature and a corresponding risc in motor bearing metal tempera-ture.
It hr.. been demonstrated by testing, discussed in part 6, th the reactor coolant pumps will incur no damage as a result of *a CCW flow interruption of 10 minutes.
2.
Two safety related transmittera are provided to redundantly 2nonitor component cooling water flow to the upper and lower reactor coolant 15 pump bearings. Two additional safety,related trdr..mitters are pro-
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I vided to redundantly monitor component cooling water flow to the
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reactor coolant pump thermal barriers. These transmitters provide flow indication and actinate low flow alarins in the control room.
A discussion of th' loss of seal injection is provided in item 1, above. This discussion justifies the use of nonsafety grade instru-mentation for seal injection flow, since loss of seal injection is not limiting in terms of continued pump operation and does not require immediate operator action.
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3.
As discussed in part 1, a loss of CCW to the motor bearing oil coolers will result in an increase in oil temperature and a corre-sponding rise in motor bearing temperature.3 estinghouse contends W
,j that the loss of CCW to the RCPs will not result in an instantaneous
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seizure of a single pump,and, further, that instantaneous seizure of two pumps simultaneously is not a credible ultimate consequence.
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- - S 'N "I h ** **v3 lesa of ccw h AMENDMENT 37.71 211.I23-5 N t%**aal tr a re,*se e,ud fe f4e a, r.,,.
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The hypothetical seizure of one RCP results in a low flow recctor
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trip approximately one second after the initiation of the event. As a result of the fast reactor trip and the ' consequential decrease in
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core heat flux, the reactor cool' ant system pressure and the clad
.f temperature reach the,, peak values at about -2.5 secon'ds-and then :.
start to decrease.
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Because the core has been shut down, at 40 seconds-or even 10 sec-onds - after a pump seizure, the reactor coolant system pressure and the clad temperature transients have decreased. to a point at which a
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second pump seizure results in no noticeable change in the tran-,,
sients.
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' 5.
Operating procedures are provided f or a los's 'of component cooling water and seal injection to L'he reactor coolant pumps and/or 15 motors. Included in these operating procedures is the provision to trip' the. reactor if component cooling water flow, as indicated by the instrumentation discussed in item 2,'above, is lost to the reac-tor coolant pump motors, and cannot be restored within ten minutes. The reactor coolant pumps will also be' tripped following
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the reactor trip.
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Two RCP motors have been tested with interrupted CCW flow; these tests were conducted at the Westingho'use Electro Mechanical Divi-sion. In both cases, the reactor coolant pumps were operated to j
achieve " hot"'(2230 psia, 5520F) equilibrium conditions. After the bearing temperrtures stablized, the cooling water flow to the upper and lower motor bearing-oil coolers was terminated and bearing (upper thrust, lower thrust, upper guide and lower guide) tempera '
[
tures were monitored. A bearing metal temperature of 1850F was established as the maximum test temperature. When that temperature reached, the. cooling water flow was restored.
was
(.. )
In both tests, the upper thrust bearing cxhibited the limiting tem-pe ra t ur es. Figure 211.123-6 shows the upper thrust bearing tempera-ture versus time.
In both cases, 1850F was reached in approxi-mately ten minutes.
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211.123-9 AMENDMENT ff h
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6 211.127 Overpressurization of Internal Body Cavity to Cate Valves in the ECCS System We have been notified of a potential design deficiency regarding double seating gate valves which are used in the ECCS systems of some PWR plants.. The concern is that when fluids, trapped in the internal body cavity of the valve, are heated due to the increased temperatures of adjacent piping systems or of.the environment, substantial pressure increases may result in these cavities that could rupture.the valve.. Provide information which addresses this potentia 1' valve problem'as it applies to the Virgil C. Summer Station.
RESPONSE
The only gate valves of the double disk design used on the Virgil C. Summer Nuclear Station are the three main feedwater containment isolation valves. These valves, however, have incorporated in their' design a trapped fluid release feature between the parallel disks to prevent overpressurization of the internal body cavity.
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211.128 Credit for Operator Action'
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Your response to questions 211.108 and 211.120 have only identified'three events that require operator manual action to. mitigate the consequences ~of an accident. The response should be expanded to specifically identify the need and the time for operator action for each Chapter 15 event.
RESPONSE
See revised response to question 211.120.
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til 51, t !!, C /, 21)* IW m **sl
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Significant event's in which a discussion of operator actions, in mitiga,
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ting'the consequences of the transient is appropriate are main steam
.,,line break, main feed line break, LOCA, and spurious actuation of the a
p
- + -
.- ECCS. ' The significance of operator action for events not mentioned 1
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above is. addressed in the response to question 211.59 which discusses thI standard ~ procedures followed to achieve a' normal plant shutdown following an event.
The safety issues of concern during the time j
sequence of operator actions in general is addressed in both the FSAR j
and, in the response to questions 211.59, 211.61, 211.108, and 211.115.,.-
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).s The limiting transient is the main steam line break.
Operator action SW 16 *
.l u s eoss..! o u + % e response to questions 211.59 and 211.108.
As stated in the response to 7
question 211.108,. the time at' which operator action is required to limit
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k the cooldown and primary repressurization following a steam line break is in excess of 10 minutes.
For the core integrity analysis following
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cither a main steam line break or depressurization of the main steam
)
system, operator action is not required at a specific time to obtain et*
- g.,' w acceptable results.
Desirable operator actions and the necessary 2
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instrumentation' for indication
.e described for the steam break type event in the response to Q ";1.59.
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15 7 In terms of establishing and maintaining long-term control of cooldown,
' the feedwater line break 'is less limiting than the steam line break for
~ the following reasons. During the early portion of,the feedwater line
+
f break, the break effluent consists of water or low quality steam which 7
carries less energy per pound than the dry, saturated steam assumed in j
r, the steam line break analysis. Also, since the maximum break size for I
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the feedwater line break is always smaller than for the steam line
)
break, the steam discharge rate must be smaller.
Thus, the plant
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co 1down is ler.s rapid and of a smaller magnitude than for the steam f
line break.
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'f, gqy/.,,, De lieresa, 211.120-2 AMENMENT L
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211.129 Submittal of Revised LOC L Analyses with Corrected Nktal-Water Reaction, and Additional S' mall Break Analyses to Insure Identification of Worst Case Small Break The licensee has revised the input to his small break LOCA model.. This revision resulted from a'QA audit which uncovered c
an input error in modeling the reactor vessel downcomer. The correction reduced the area of the downcomer by a factor of
- 2. from 52 to 26 ft2 This input correction resulted in a 0
predicted peak clad temperature decrease of 125 F.for the 1
3-inch break (1833 to.1708 F). The staff is presently evalu-ating'this modification. However, we require that you formally document the corrections made to your small break LOCA model, j
and revise the analyses presented in the FSAR.
In' addition, you should discuss why the limiting small break size is not less than 3 inches in diameter (yet greater than 2 inches, 4
which is the size. capable of.being mitigated by the charging i
pump alone).
RESPONSE
This information will be provided later.
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211.130 Isolation of Lines Between MISV and Turbine Stop Valves on ESFAS Table 10.3-3 of your FSAR indicated that several main steam line valves downstream of MISV's will remain open on ESFAS.
Confirm that the assumed steam release from unaffected steam generators following a main steam break accident as listed in Table 15.4-23 has included the steam released from the open valves identified in Table 10.3-3 and the steam supply to the turbine driven auxiliary feedwater pump.
RESPONSE
The flow given in Table 10.3-3 are the maximum for which the equipment is designed.
Flow from the steam traps is dependent on the rate of steam condensation in the main steam lines.
The need for pegging steam to maintain deaerator temperature would be greatly reduced as soon as main feedwater flow is stopped.
The procedure that is used to calculate the steam released to the atmosphere from the unaffected steam generators in Chapter 15.4 is based on an energy balance between the reactor coolant system and the steam generators.
The calculation consist of calculating the total system energy before the steamline break, adding the energy release (decay heat) over the time span of interest, and subtracting the total system energy at the end to get the amount of heat which must be dissipated by the steam generator safety valves.
After the steam line break the plant is assumed to stabilize at no load conditions within two hours, then cooled down in a six hour time period to where tha RHR (Residual Heat Removal i
System) starts operation (4000F, 600 psia). At this point, atmospheric steam dump is no longer needed to relieve decay heat.
The steam release presented is the total energy dissipated over 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to get the system to RHR temperature and pressure.
This includes the decay heat and also a ten percent factor of conservatism.
This steam release presented is independent of the flow paths taken.
If we assume all the flow paths available in Table 10.3-3, we would get less energy release to the atmosphere.
This is due to the heat capacity of the piping,-friction losses, etc.
Since we do an energy balance over the RCS and SG, the numbers we pre-sent in Table 15.4-23 are clearl; limiting.
.It should also be noted that credit for operation after 20 minutes
' can be assumed. If the main steam isolation valve fails to close, the coerator could isolate the flow paths identified in Table 10.3 3.
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211.131
. Analyses of Roron Dilution Events from Hot Standby and
' Cold Shutdown a.
It is required by the Standard Review Plan that you analyze unplanned boron dilution events. Since the sequences of events that may occur depend on plant
)
conditions at the time af the unplanned moderator dilution, the analyses should include conditions at the time of the unplanned dilution, such as refueling, startup, power operation, hot standby and cold shutdown.
Your Chapter 15 analyses did not include analyses of hot standby and cold shutdown. We request that you include this analyses in your FSAR'.
b.
What are the assumed causes of an unplanned reactivity insertion during refueling, startup, and at pc'esr?' What are the necessary actions to be.taken by the operator to mitigate each of these events?
e Identify the actions to be taken by the operator in the event of the worst single failure postulated in the mitigat-ing system, and show that the time available to the operator to mitigate the event including the effects of the single failure, is sufficient.
RESPONSE
This information will be provided later.
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211.132 Containment Sump and its effect on long term cooling following a LOCA During our reviews of license applications we have identified concerns related to the containment sump design and its effect on long term cooling following a Loss of Coolant Accident (LOCA).
... ~.......
These concerns are related to (1) creation of debris which could potentially block the sump screens and flow passages in the ECCS and the core, (2) inadequate NPSH of.the pumps taking suction from the containment sump, (3) air entrainment from streams of water or steam which can cause loss of adequate NPSH, (4) formations of vortices which can cause loss of adequate NPSH, air entrainment and suction of floating debris into the ECCS and (5) inadequate emergency pro-cedures and operator training to enable a correct response to.these problems. Preoperational recirculation tests performed by. utilities have consistently identified the need for plant modifications.
The NRC has begun a generic program to resolve this issue.
- However, more immediate actions are required to assure greater reliability of safety system operation. We therefore require you take the following actions to provide additional assurance that long term cooling of.the reactor core can be achieved and maintained following a postulated
- AOCA, 1.
Establish a procedure to perform an inspection of the containment, and the containment sump area in particular, to identify any materials which have the potential for becoming debris capable of blocking the containment sump when required for recirculation of coolant water. Typically, these materials consist of: plastic bags, step-off pads, health physics instrumentation, welding equipment scaffolding, metal chips and screws, portable inspection lights, unsecured wood, construction materials and tools as well as other miscellaneous loose equipment.
"As licensed" cleanliness should be assured prior to each startup.
This inspection shall be performed at the end of each shutdown as soon as practical before containment isolation.
2.
Institute an inspection program according to the requirements of Regulatory Guide 1.82, item 14.
This item addresses inspection of the containment sump components including scrcens and intake structures.
3.
Develop and implement procedures for the operator which addresses both a possible vortexing problem (with consequent pump cavitation),
and sump blockage due to debris.
These procedures should address all likely scenarios and should list all instrumentation available to the operator (and its location) to aid in detecting problems which may arise, indications the operator should look for, and operator actions to mitigate these problems.
4.
Pipe breaks, drain flow and channeling of spray flow released below or impinging on the containment water surface in the area of the sump can cause a variety of problems; for example, air containment, cavitation and vortex formation.
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^
Describe any changes you plan to make to reduce vortical flow in the neighborhood of the sump.
Ideally, flow shonld approach uniformly from all directions.
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5.
Evaluate the extent to which the containment supp(s)..in your..--
plant meet the requirements for each of the items previously identified; namely debris, inadequate NPSH, air entrainment, vortex formation, and operator actions.
The following additional guidance is provided for performing this evaluation.
1.
Refer to the recommendations in Regulatory Guide 1.82 (Section C):
which may. be of assistance 'in performing this evaluation.
2.
Provide a drawing showing the location of the drain sump relative to the containment sumps.
3.
Provide the following information with your evaluation of debris:
Provide the size of openings in the fine. screens and compare a.
this with the minimum dimensions in the pumps which take suction from the sump (or torus), the minimum dimension in any spray nozzles and in the fuel assemblies in the reactor core or any other line in the recirculation flow path whose size is comparable to or smaller than tha sump screen mesh size in order to show that no flow blockage will occur at any point past the' screen.
b.
estimate the extent to which debris could block the trash rack or screens (50 percent limit).
If a blockage problem is identified, describe the corrective actions you plan to take (replace insulation, enlarge cages, etc.).
For each type of thermal insulation used in the containment, c.
provide the following information:
1.
type of material including composition and density, ii. manufacturer and brand name, iii. method of attachment, iv.
location and quantity in containment of each type, i
an estimate of the tendency of each type to form particles v.
small enough to pass through the fine screen in th'e suction lines.
d.
Estimate what the effect of _hs e f esuin'. ion particles would be on the operability am( p gfessance <.c all pumps used for Uf fects on pump seals and recirculation cooling. A Ak t e
bearings.
Additionally, previous in-plant sump tests did not securately replicate expected post-LOCA conditions, and thus did not demonstrate-acceptable sump performance under ECCS recirculation conditions..
Specifically, the plant test only pulled suction from a single line, when there are two lines in each of two sumps. This resulted in gest approach flow velocities which were lower than would be expected i during a LOCA.
Additionally, various flow approach directions were not investigated to determine if undesirable rotation could be induced'in the sump-area, which could lead to vortex formation.
Finally, sump screen blockage due to debris entrainment was not considerea, with the correspondingly higher screen velocities which also could aggrevate vortex formation.
The applicability of your sump tests, and the adequacy of your sump design under post-LOCA conditions, in light of these staff concerna should be addressed to provide assurance that recirculation sump performance will be acceptabl. following a postulated LOCA, and that undesirable vortex formation will not be experienced.
RESPONSE
This information will be provided later.
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