ML19275H317
| ML19275H317 | |
| Person / Time | |
|---|---|
| Site: | Midland |
| Issue date: | 03/08/1978 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML111090060 | List:
|
| References | |
| FOIA-80-515, FOIA-80-555 NUDOCS 8006240682 | |
| Download: ML19275H317 (14) | |
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211-1 211.0 REACTOR SYSTEMS BRANCH 211.16 What is the basis for limiting the missile selecticn criteria (3.5.1.1) to high energy systems? Provide justification to show that missiles with lower energy levels would not fail any safety-related equipment.
211.17 Section 4.6.3.1 of the Midland FSAR states that the CRDM's to (4.6.S.1) be used in the design are " essentially" identical to that supplied on previously reviewed plants.
Discuss any modifica-tions and the justification for each. Include relevance to previous prototype testing.
211.18 Provide a discussion and bases for relief valve setpoints ano (5.2.2.4) capacities.
211.19 Since it is assumed that pressurizer and steam safety valve (5.2.2) accumulation is 3",or less, how is this verified?
211.20 Review of Section 5.2.2.2a and 5.2.2.2g shows that increments (5.2.2) for flux measurement uncertainties and safety valve setpoint tolerances are not included. Add these items or provide justification for their omission.
211.21 Does the pressurizer safety valve capacity reflect the capacity (5.2.2.4) as installed (i.e., has the effect of associated piping been included)?
211.22 Check valves in the discharge side of the high pressure injection, (5.2.2) low pressure injection, and DHR systems perform an isolation function in that tney protect low pressure systems from full reactor pressure.
The staff will require that these check valves be classified ASME IWV-2000 Category AC, with the leak testing for this class of valve being performed to code spec.i fications.
It should be noted that a testing program which simply draws a suction on the low pressure side of the outermost check valves will not be acceptable.
This only verifies that ene of the series check valves is fulfilling an isolation function.
The necessary testing freauency will be that specified in the ASME Code, except in cases where only one or two check valves separate high to low pressure systems.
In these cases, leak testing will be performed at each refueling after the valves have been exercised.
Identify all ECCS check valves which should be classified Category AC as per the position discussed above.
Verify that you will meet the required leak testing schedule, and that you have the necessary test lines to leak test each valve.
Provide the leak detection criteria that will be proposed for the Technical Specifications.
211.23 Regulatory Guide 1.45 states that identified and unidentified (5.2.5.2) leakage should be collected spearately. The discussion in 8006240bh
q 211-2 (5.2.5.2)
Section 5.2.5.2 indicates that all leakage, identified and unidentified, will be collected in the reactor building sump. Provide a discussion of the method used to distingui':h unidentified from identified leakage.
211.24 Provide a discussion of the method of detecting intersy tem (5.2.5) leakage; specifically leakage to the core flood, decay heat removal, HPI, nitrogen, and vent and drain system as required by Regulatory Guide 1.45.
211.25 Regulatory Guide 1.45 requires charts and graphs to convert (5.2.5.3) containment air monitor signals to equivalent gpm leak rates to assist the operator in interpreting signals.
Address this capability for Midland Units 1 and 2.
Alarm set points and their correlation to leak rate should also be provided.
E11.26 Discuss the capability to take a grab sample of the containment (5.2.5.7) atmosphere on a periodic basis and to manually analyze these samples for particulate activity and to correlate the data to primary system leakage.
211.27 Regulatory Guide 1.45 requires that the three methods used in (5.2.5) unidentified leak detection be able to detect a one gpm leak in one hour.
Discuss how you intend to meet this requirement, particularly with regard to the gaseous radioactivity monitor.
Also, the FSAR does not provide a clear explanation of how the sump level and flow monitoring system can detect a one gpm leak in one hour.
Discuss in some deta:1 the operation of this system with regard to leak detection sensitivity.
211.28 State the expected range of the variables monitored for uniden-(5.2.5) tified leak detection and the limits to which the instrumentation can cover this range and still detect and alarm a one gpm leak in one hour.
211.29 During plant startup or after an extended outage, coolant (5.2.5) activity may be low enough such that containment activity due to the presence of small leaks may be belcw the threshold sensi;ivity of the radiation monitors used for leak detection.
Describe how you intend to monitor RCPB leakage without the use of this equipment until containment activity has increased to a detectable level.
211.30 Once an unidentified leak has been detected, what procedures (5.2.5) will be used to locate the source of leakage?
211.31 The FSAR does not state that Q leak detection systems can (5.2.5) nerform their functions fol? swing a seismic event that doas not require plant shutdown as required in Regulatory Guide 1.45.
Show that the Midland plant meets this requirement.
Q 211-3 211.32 Describe the provisions for detecting leakage frem the primary (5.2.5) coolant system to the RHR and ECCS through injection and return lines during normal power operation.
Describe the indications, alarms, and procedures for isolation to limit releases and show conformance with Reculatory Guide 1.45.
Discuss the procedures used by the operator to corvert all leak detection indications in the control room to a ccmmon leakage equivalent, e.g., cpm to gpm.
211.33 Discuss the basis for determining the alarm setpoints for all (5.2.5) three unidentified leakage detection systems.
211.34 Describe the procedures used to calibrate the radiaticn (5.2.5) monitors and sump level and ficw monitors to RCPB leakage.
211.35 Should the Midland plants experience an event that will require (5.a.7) eventual cooldown to termit either long-term cooling with the CHR system cr going to cold shutdcwn for inspection and repairs (extended loss of offsite power, steam generator tube rupture, failure of steam generator relief valves to reclose, etc.), it is desirable that qualified systems be available to perform the operation safely and in an orderly manner.
Discuss the capacility of the Midland plants to Se taken to a cold shutdown condition using only safety-grade equipment, assuming enly onsite or offsite power is available, and considering a sirgle failure.
Address cach of the following areas of concern in your response:
(1)
Discuss the cacability of ne single CHR drcp line to provide for the ccoldown of the plant assuming a single active failure, including manual actions insice or cutside of containment or the return to hot standby until manual actions or maintenance can be cerformed to correct the failure.
With regard to the Midland shutdcwn capability, we note that manual operation outside the control reem is required for normal shutdown and containment entry is required for a failure of a motor-ocerated CMR suction valve.
With regard to reducing the need for such manual actions, address the following areas:
( a)
Discuss the modifications recuired to provide the cacacility to conduct a normal shutdcwn frca the con rol roCm.
p 211-4 (5.4*7)
( b)
Justify the viability of the manual actions required after a suction valve failure (i.e.
cpening cross-connects 093,094). Address times recuired, doses ex::ected, and potential for inadvertent opening of cross-connects during high primary side pressure conditions.
Compare the Midland cross-con act design to Davis-Besse Unit 1.
Provide a reliability analysis for the manual action outside the control room and discuss the incremental increase in reliability expected for various selected design modifications.
(2)
Provide safety-grade steam generator dump valves, operators, air and power supplies which meet the single failure criterion.
(3)
Provide the capability to ecol down to cold shutdcwn assuming the most limiting single failure in less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> or show that manual actions inside or outside containment or return to hot standby until the manual actions or maintenance can be performed provides an acceptacle alternat;,ve.
(a)
Provide the capability to depressuri::e the reactor coolant system with only safety-grade systems assuming a single failure, or show that manual actions inside or outside containment or remaining at hot standby until manual actions or repairs are comolete provides an acceptable alternative.
(5) Discuss the capability for boration with only safety-grade systems assuming a single failure or show that manual actions inside or outside containment or remaining at hot standby until manual action or recairs are c:mpleted provides an acceptable alternative.
(6)
Discuss the capability for the collection and containment of CHR system pressure relief valve discharge.
(7) Conduct tests to study the mixing of the added borated water and the cooldown under natural ci-culation conditions with and without a single failure of a steam generator atmospheric duma valve.
(3)
C = nit to aravicing specific precedures for cooling dcwn using natural circulation and submit a summary of these precedures.
(9)
Provide a Seismic Category I AFW su:: ply for at iaast four hours at hot shutdcwn plus ccoldewn to the CHR system cut-in based on the icngest time (for cnly Onsite or offsite power and assuming the worst single failure), or show that an adequate alternate Seismic Catagory I source is available.
G 211-5 211.36 Table 5.4.10 should be expanded to include sizing criteria (Table and backpressure cor.siderations.
This table also indicates 5.4.10) 1007, accumulation.
This error should be corrected and the (6.3.2.2) value selected should be justified.
Hcw will this value be confirmed thrcughout plant life?
211.37 Cn Figures 5.4-10 and 5.4-11, the hign pressure line designations (5.4.7) are "CCA."
Per Figure 1.1-2, this correspends to a 1500 pound pressure rating.
It would appear that the line designations or the c. odes on Figure 1.1-2 are in error. Verify that the letdown lines and injection lines inside the containment isolation valves are cated at primary plant pressure, 211,38 Section 5.4.7.1.1.3 states that the CHR suction relief valve (5.4.7) is sized for the "most rapid rate of pressure increase."
Provide the complete quantitative basis for the si:ing of this valve.
Provide analyses of the ccmcenent failures er coerator errors which cculd initiate an overpressure transient during plant cooldown.
Discuss all assumptions and ycur analyils technin"9s-211.39.
Referenced figures (5.a-10, 5.4-11, 9.3-32, and 9.3-34) must (6.3) be excanded to show ECC injection and recirculation valve positions in addition to normal positions.
provice or reference piping identification diagrams which shcw all of the ECCS including the 5'AST.
211.40 Figure 6.3-3 shows that since HP! ficw from injection cressure (6.3.2.2) and below is expected to be greater than 300 gpm, tne high ficw alarm (253 cpm) will always alarm.
Clarify this discrecancy.
What is the basis fcr the high ficw alarm setpoint?
211.11 Discuss the provisions and precautions for assuring proper (6.3.2.5) system filling and venting of ECCS to minimize the potential for water hammer and air binding.
Address piping and pump casing venting provisions, accessibility, and surveillance frequencies.
211.42 Provide the basis for ECCS lag times.
Are these times calculated (6.3.3.8) or verified by test?
If calculated, they must te verified in creoperational test, then pericdically reverified.
211.23 Provide justification for not including the nitrogen system (5.3.3.9) used to pressurire the core floed tanks in this section (system dependency).
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211-6 211.44 Explain the relevance of Table 5.3.1 to the ECC3 analyses.
(Table Also, address the folicwing:
6.3.1)
(1)
Justify the use of normal values rather than the worst-case (minimum or maximum) values.
(2) Why is a maximum boron value s;:ecified for the core flood tanks and not for the borated water storage tank?
(3)
For core flood tanks, units should be added to level alarm setpoints; also, equivalent ft3 should be listed.
(4)
Same comment as above for SWST.
(5)
No cleanliness level is given for the SWST.
Why are different ccmconents in the same system assigned different cleanliness levels (i.e., LPI cumes are level 3, while decay heat remotal coolers are C)?
211.45 With rescect to the core ficed tank line break, Table 5.3-6 is (Table not ccmplete in that the effect on the reactor was not clearly 6.3-6) addressed.
For example, the table shcws that for the CFT line break, the loss of :oth L?I trains has no effect on plant operation, however, in the cost-LOCA mcde, the effect may be severe in regard to ecoling the core.
The FMEA must clearly low the systems available to cool the core.
211.26 With rescect to Table 5.3-6 address the followinc:
(Taole
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6.3-6)
(1)
Ocerator mitigation states RCS pressure maintained with LPI pumes.
Per pump data in Section 5.3, shutoff head of LPI pumos is approximately 200 psi.
Should this be HPI pumps?
(2)
It is noted that CFT pressure is 5C0 - 15 psig while C F isolated alarm is 750 osig. Accresi the consecuences of a LCCA with the CFT's isolated (0700 psig),
(3)
For the LCCA in the CF line break, exclain hcw ficw is divided between 50 LPI flow :aths.
What indications are used and what action is recuired?
211.47 The Table 6.3-7 is not comolete.
Add a column for the metnce (Table of detection.
Also, the pump seal failure snould be added to 5.3-7) this table.
(5.3)
(5.2.7)
Provide more detailed information on the proposed leakage collection and the detection system.
Discuss orovisions for identifying the locatior' af the leak and tha time recuired to identify various size leaks under post-LCCA concitions.
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(Table Our rsquirements for leakage detection of ECCS equipment 6.3-7) passive failures (such as valve stem packing and pumo seals)
(6.3) are stated below.
(5.2.7)
Cetection and alarms must be provided to alert the operator to passive ECCS fatiures during long-term cooling which alicw sufficient time to identify and isolate the faulted ECCS lir..
The leak detection system should meet the following requirements:
(1)
Identification and justification of maximum leak rate should be provided.
(2). Maximum allowable time for operator action should be provided and justified.
(3)
Demonstration should be provided that the leak detection system will be sensitive encugh to initiate (by alarm) ooerator action, permit identification of the faulted line, and isolation of the line prior to the leak creating undesirable consequences such as flooding of redundant equipment.
The minimum time to be considered is 30 minutes.
(4)
It should be shown that the leak detection system can identify the faulted ECCS train and that the leak is isolable.
(5)
The leak detection system should meet the following requirements:
(a)
Control room alarm (b)
IEEE-279, except single failure requirements.
211.aa Regulatory Guide 1.79 s::ecifically recommends the following (6.3.4.1) tests be perfor ed:
(1) the capability of the HPSI pumps to take a suction from the L?SI pumos should be demonstrated, (2) pumo flow test should be initiated by the safety injection signal.
provide a listing of the tests required by Regulatory Guide 1.79 and provide confirmation of ycur intent to imolement each test procedure or address ncnconfor ance.
!dentify specific deviaticns and crovide justification.
C 211-8 l
(6.3.4.1)
Assurance must be provided that the low pressure injection system can take suction frcm the recirculation sump, verifying vortex control and acceptable pressure drops across screening and suction lines and valves.
Submit a test plan which satisfies this portion of the Regulatory Guide 1.79 requirement.
211.49 In Table 6.3-6, isclation fer an HPI line break is stated as (6.3) being ensured by closure of either isolation valve 446 or 499 for Unit 2 (346 or 399 for Unit 1).
Valve 499 (or 399) is not presently shown on the respective makeup and purification diagrams in Section 9.
211.50 In Table 5.1-12, spurious closure of the OHR reactor building (6.3) isolation valve 1120A, 8 is considered for normal CHR operation.
In Table 6.3-6, spurious closure of this valve is considered as not being credible for ECCS operation since the valve is locked open.
The valve appears to be locked coen for either mode of operation.
Resolve this discrepancy between the two failure analyses.
211.51 The ECCS for the Midland plants centains manual as well as (6.3) motor-operated valves.
Consideration must be given to the possibility that manual valves might be left in the wrong position and remain undetected when an accident occurs.
Provide a list of essential manually ocerated valves in the ECCS and a discussion of the methods used to minimize this occurrence for each valve.
The list should also include all manual valves in the ECCS for which valve position is not indicated in the control rocm.
Address the recuirements of Regulatory Guide 1.17 in ycur res;cnse, Verify that there is no one manual valve which could interruct the flow to both ECCS trains.
211.52 Submit ECCS P&ID's which are the final clant arawings used for (6.3)
Midland construction.
The cencern is that inadecuate information exists in the presented simolified schematics to allow an adecuate evaluation (see question 211.39).
The size of the drawincs should be large e.nough to ansure legibility of valve designations,'etc.
211.53
'4ith regard to the conservatism of NPSH calculations, the (6.3)
" required" flPSH has often been defined as a fixed number as provided by the architect engineer or the pumo manufacturer.
Since several methods exist to calculate the recuired NPSH and the method used can affect the suitability of a particular cumo, it is requestec that Midland provide and justify the basis on which the required NPSH was determined (i.e., testing, Hydraulic Institute Standards) for all ECCS pumos and the estimated NPSH variability between similar pumas.
Include a discussion of all inaccuracies.
211.54 Recenc plant experience has identified. 3 potential problem (6.3) regarding the operability of the pumps t. sed for lonq-term cooling (normal shutdown as well as post-i.CCA) for Je time period required to fulfill thaOunction,
?rovide the pump design lifetirre
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(6.3)
(including operational testing) and compare to the continued pump operational time required during the short and long term of a LOCA.
Submit information in the form of tests or operating experience.
'/erify that these pumps will satisfy long-term requirements.
211.55 So that we may evaluate the dependence of the ECCS equipment (6.3) on the plant auxiliaries, provide, or reference in the FSAR, the following:
(1) A list of all of the primary auxiliary systems required to directly support each ECCS c mponent.
(2) A brief description of the supporting function performed by the primary auxiliary.
(3)
The method of initiating the primary auxiliary to provide suoport to the ECCS.
(4)
The additional secondary auxiliaries recuired to directly support the primary auxiliary specified in (1).
(5) A brief descripticn of this supporting function performed by the secondary auxiliary.
(6)
The method of initiating this secondary auxiliary.
211.56 The Midland FSAR references SAW-10103, "ECCS Analysis of B&W's (6.3) 177-FA Lowered Leap NSS" for preventing excessive baron precipitaticn during long-term cooling.
Accroval of this portion of SAW-10103 was deferred by the staff to a plant-specific basis.
Therefore, provice or reference information for the Midland plants addressing the folicwing design guidelines:
(1)
The barcn dilutien function shall not be vulnera:1e :: a single failure.
A-single active failure ;cstulatec :o occur during the icng term c cling period can te assumed.
Mcwever this failure would then be in lieu of a single active failure during the shcr: term ::aling ;ericd.
(2) The inadvertent c:eration of any motor c:eratec valve (0:en or cicsed) snail nc: ccmcr: mise the Oce:n ciiuti n func:icn nce snall i: jec:arti:e One scility :: rencve decay hea: Fr m :ne :rimary systam.
(3) Ali ccmcenents of :ne sys:am wni:n are witnin ::ntainmen; shall be designec :: seismic Ca:agery ; recuiremen:s anc classfied Quality Greu: 3.
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(6.3)
(4) The rimary mcde fcr maintaining accectable leveis cf baron in the vessel shculd be established.
Shculd a single failure disable the primary mcde, certain manual actions outside the centrol r0cm would be alloweds. depending on the nature of the action and tne time availacle to establish backuo mcde.
(5) The average beric acid concentraticn in any regicn -af the reactcr vessel shculd not exceed the level of four weign:
percent belcw tna solubility limits at the tem:erature of the solution. - -.
(5) Curing the ;cs:-LCCA Icng term c: cling, :ne ECC syttes normally c:erates in two modes:
- ne initial colo leg injection mcde, folicwed by the dilutien mode.
The actual coerating time in the cold leg injecticn mcde will depend en alant design and steam binding c:nsideraticns, but, in general, :ne switcnover :: the dilution mcde snculd be mace between 12 and 21 ncurs after LCCA.
(7)
The dilution mcde can be ac::mplished by any of the fclicwing means:
(a) Simultanecus c id leg injection and ha leg sucticn (b)
Simul:anecus he: and cold leg injec:icns (c) Alternate het and ccic leg injections.
(S)
In the alternate not and cid leg injection mcde, :ne ccera:ing :ime a: nc: and ::id leg injecti:n sncuid be sufficiently snor: Oc areven; excessive boric acid builcuc.
(g) The minimum EC:5 ficw rate deitvered to the vessei during the dilutien acce shall be sufficient :: ac::=mccate :ne boil-cff due :: fission crecuct cecay heat and ;cssible li uid entrainment in tne steam discharged :: tre c:n-tainment and still provide suf'icient liquid ficw :nr0ugn the core to crevent further increases in beric acid concentra:icn.
(10) All diluticn modes shall maintain testacility c:mparable to other ECCS medes of ::eraticn (HP!-snor: term, L:I-sacr term,e:c).
The current critaria fcr levelt of ECCS testability shall be used as ;uicalines (i.e.,
Regulat:ry Guides 1.53, 1.79, GCC 27).
(11)
The ccerator should be cacable of confir.ning minimum required ficws subsaquen: to a LCCA.
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211-11 211.57 Discuss the potential for, and the precautions taken, to (6.3) prevent crystallization of boric acid in the safety injection system.
For example, ocerating experience has shown instances where the high head safety injection pump was able to achieve only about one half of the pumo discharge pressure because the suction elbow and the eye of the pump were found to be plugged with solidified boric acid crystals.
211.58 Secause of freezing weather conditions, blocking of the vent (6.3) line on the BWST has occurred on at least one operating plant.
Describe design basis and features that preclude this condition frem occurring in the Midland plant.
211.59 Table 15.0.2 gives a pressure / temperature trip delay of 0.7 (15.0) second.
Since one of the inputs to this trip is the hot leg temperature, which has a delay of 5 seconds, the 0.7 second delay would apoear to be in error, provide the correct trip delay and verify that this value has been used in the analyses.
211.50 provide a confirmation, with bases, that all transient events (15.0) would not exceed the acceptance criteria for abnormal operational occurrences when credit is not taken for nonsafety-grade systems (turbine trip, turbine bycass, pilot-operated relief valves, etc.).
The discussion for the turbine trip analysis in Section 15.2 gives the impression that the analysis was conducted assuming the failure of one nonsafety-grade system at a time.
Clarify this discussion to show that no credit for ncnsafety-grade ccmpenents is taken in the analysis.
211.61 With regard to the turbine trip analysis, provide the scroke (15.2.3) time for the turbine stop valve closure and verify that the analysis of Section 15.2.2 is conservative if the initiating event for the transient is stop valve closure.
211.62 Provide a plot of DNBR versus time for the loss of electrical (15.2.2) load and/or turbine trip transient.
211.63 Many of the sections in Chapter 15 refer to other transients (15.0) as providing a limit for the transient under consideraticn (e.g., 15.2.1 refers to 15.2.7).
Previde the accrcoriate justification and bases to supcort this positicn.
211.54 The loss of condenser vacuum transient is stated by Section (15.2,5) 15.2.5 to be bounded by the turbine trip analysis of Section 15.2.2.
As currently presented, the turbine trip analysis assumes that the condenser dump system remains operational.
Additicnal analysis reflecting loss of the con-denser must be presented either here or in Section 15,2.2.
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211.65 Provide your justification for classification of the loss of (15.2.6)
AC power as an infrequent event.
This justification should include an actual operational data base.
211.66 Section 15.2.6.2 states that for a loss of nonemergency AC (15.2.5) power, "It is assumed that the operator further opens the atmospheric duma valves 10 minutes after the loss of power."
To take credit for operator action after 10 minutes, a complete description of each action and appropriate justification must be provided, or the assumption of no operator action for at least 20 minutes must be used.
211.6 7 It is noted that many incidents of mcderate frequency in (15.0)
Chacter 15 refereice 10 CFR 100 for the dose limit.
This is not in itself an acceptable reference.
All analyses of events of moderate frequency must shcw that no fuel damage results (MONBR<1.30) and that the peak pressures of the reactor coolant and main steam systems do not exceed 110", of design cressure.
Revise or resubmit your analyses to shcw how Midland meets tnese criteria.
211. 68 Provide a plot showing DNBR as a function of time for the (15.2.7) loss of normal feedwater transient.
211.69 The feedwater piping break analysis infers that no fuel (15.2.8) failure occurs.
Confirm that this is correct and provide a plot of CNBR versus time to justify this conclusion.
211.7 0 Provide a sequence of events table for the uncontrolled rod (15.4.1) group withdrawal transients.
(15.4.2) 211.71 Provide the minimum DNBR and the maximum linear heat generation (15.4.1) rate for the startup rod withdrawal accident.
211.72 Provide the maximum linear heat generatien rate for the (15.4.2) uncontrolled r:d grouc withdrawal at pcwer transier.t.
211.73 Provice a plot of CN5R versus time for the startup of inactive (15.J.a) reactor coolant pumps.
211.7 4 With regard to an inadvertent operation of ECCS during power (15.5.1) operaticn, Section 15.5.1.2 states that after reactor trip,
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211-13 (15.5.1) the operator terminates HPI flow.
Is this action necessary for plant safety? Provide a sequence of events table which includes the time frame for operator action. Also, provide figures showing appropriate plant parameters as a function of time (pressure, OfiBR, pressurizer level, etc.).
211.75 Section 15.6.1 states that the inadvertent opening of a (15.6.1) pressurizer safety valve is limited by the small LOCA analysis and thus is not specifically analyzed.
This transient is defined as an incident of moderate frequency and thus the acceptance criteria for a LOCA do not apply.
Pre ide an analysis for this transient evaluating the conseg.ences with respect to the minimum DtlBR limit of 1.30 or demonstrate that the small LOCA analysis results meet the acceptance require-ments for an incident of moderate frequency.
211.76 With regard to a break in an instrument line or line from a (15.6.2) primary system that penetrates containment, discuss the effects of an additional single active failure resulting in the failure of the letdown isolation valve to close.
211.77 With regard to the dilution event, verify that the maximum (15.4.6) dilution rates given in Table 15.4-11 are conservative, especially for lower reactor vessel pressures.
(See Figure 6.3-3 which shows a flow rate from one pump of approx wately 350 gpm at 2000 psi and increasing to 600 gpm at runout.)
Provide plots of appropriate plant parameters versus time for the dilution accident at power (e.g., power level, RC pressure, CNBR, etc.).
211.78 Recently, an operating PWR experienced a boron dilution (15.4.6) incident due to inadvertent injection of NaOH into the reactor coolant system while the reactor was in a cold shutdown condition.
Discuss the potential for a boron dilution incident caused by dilution sources other than the CVCS.
211,79 Table 15.1-5 gives a time for auxiliary feedwater flow (15.1.5) initiation of 16.3 seconds, or 15 seconds after the initiating setpoint.
This is inconsistent with the value of 40 seconds
.given in Section 10.4.9.2.3.
Correct this discrepancy and verify that the. proper delay was assumed in the steam line break analysis.
211.80 With regard to a loss of AC power, Section 15.2.6-2.a infars (15.2.6) that the operator initiates the C7CS for addition of boric acid to maintain shutdcwn margin.
Discuss the time frame associated with this operator action and show that it is acceptable.
p 211-14 211.81 The response to question 211.2 does not provide sufficient (15.1.4) information to justify using the steam pressure regulator malfunction as the bounding analysis for the inadvertent opening of steam generator atmospheric dump or safety valve.
Provide the appropriate steam flows resulting from the turbine throttle valve valve wide open condition, the safety valve and dump valve flows and show that your analysis assumptions representing these steam flows are justified.
211.82 The response to question 211.15 does not provide sufficient (15.0) information for the staff to make an adequate evaluation.
Provide a discussion of the loss of instrument air event for the Midland plant.
Recently, a loss of instrument air at an operating plant caused a loss of reactor coolant pump (RCP) seal water injection flow and component cooling water to the RCP thermal barrier and a resultant need for cooldown with natural circulation.
Please prnvide a complete discussion addressing all systems important to plant operation (CVCS, component cooling water, auxiliary systems, etc.) which are affected by a loss of instrument air.
Show that the loss of air would not introduce a failure mode which would prevent safe shutdown of the plant and address all potential system interactions.
Discuss any actions which would have to be taken by the operator.
211.8 3 With respect to a break in a high or moderate energy piping (15.0) system outside containment (DHR, CVCS, letdown, etc.) provide the following:
(1)
Determine the maximum discharge rate from the systems based on its classification as a high or moderate energy line.
(2) Determine the time frame available for recovery based on the discharge rates calculated above and their effect on core cooling.
(3)
Discuss the alarms that are available to alert the operator to the event, the recovery procedures to be used, and the time available for the required operator actions.
(4)
In evaluating the recovery procedures, the single failure criterion should be applied consistent with Standard Review Plan 3.6.1 and Branch Technical Position APCSB 3-1.
211.84 Section 15.1.2.3.3 infers that several nonsafety-grade systems (15.1.2)
(i.e., steam generator level control, condenser dump, and atmospheric vent) are assumed to operate during the feedwater system malfunction transient. Use of these systems would appear to reduce the effects of the transient. Justify the use of these systems as being conservr.tive or provide an analysis which does not consider their operation (see question 211.62).