ML19289G318
| ML19289G318 | |
| Person / Time | |
|---|---|
| Site: | Crane, Midland  |
| Issue date: | 09/28/1978 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML19289G307 | List: |
| References | |
| NUDOCS 7908220472 | |
| Download: ML19289G318 (22) | |
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211-17 211.0 REACTOR SYSTEMS BRANCjj, 211.95 With respect to missile. crotection inside containment,the structures, nur nosition (3.5) is that the Midland FSAR does not adequately show how systems, and components (SSC) inside containment, whose failure could prevent safe shutdown of the plant or result in significant uncontrolled release of radioactivity, are protected from each of the potential missile sources. Provide a table which lists each safety SSC inside containment, how it is protected (barrier redundancy, etc.) and the associated diagram where this protection can be evaluated.
211.96 The list of missiles in the Midland FSAR Table 3.511 does not include (3.5) such missiles as:
(1) Check valve bonnet and pivot studs (2) CFT isolation valve bonnet studs (3) Pressuri:er heater bundle studs (4) Containment isolation valve (inside containment) bonnet studs.
Our cosition regarding this table is that inadequate justification has been provided to rule out missiles of t!)is tyoe. Provide this justification,or provide adequate protection from these postulated missiles.
211.97 The response to question 211.25 does not adequately address the (3.5.1.*.) preoperational testing of systems in accordance with Regulatory (14.2)
Guide 1.68.
The Midland FSAR, Section 14.2.7, references Regulatory Guide 1.63, November 1973, which has been superseded by Revision 1. January 1977. As an examole, Revision 1 requires that at least two scram timings of each rod be performed. The Midland FSAR (Section 14.2.7, or Accendix laA Test Abstracts) does not provide a commitment to this test or provide justifi-cation for departing from this test requirement. Discuss this specific test area and address the other reactivity control system testing requirements covered in this revised guide and your intentions regarding each test.
E'.l.98 Sr.0 ;:I t".'.: "Se 55.d b'.;t C7 t'.r.*.-filiCd l'.r.t! '.S biCI'.;ical (3.5) shielding inside containment. These tanks or bags would ructure (5.3) and release sand to the containment in the event of a LOCA. This debris, if present, could potentially cause damage to the ECOS during the recirculation mode. Address this concern for the Midland units.
211.99 During the review of an operating clant, it became accarent -hat
'3.5) the vessel seal ring, wnica provices a seal bet..een.ne ciclogical shield and the vessel, could become a missile during a postulated LOCA.
tcdress this concern f:r the Mioland units.
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211-18 211.100 Interim reports dated February 10, 1978, March 30, 1978, June 30, (3.5) 1978, from S. Howell (Consumers) to J. G. Keppler (NRC) discuss the design deficiency in the reactor coolant pump motor mounting flanges. Sufficient infomation does not exist in these letters for the staff to review your proposed corrective action for this deficiency. Justification must be provided to show that the reactor coolant pump motor would not become a missile when subjected to LOCA and SSE loadings. Provide such justification, to include drawings of the motor mount rabbet, support stand, cap screws, and stud tensioners.
Include on the drawing the error in the rabbet ~
height dimension on the motor mounting flange.
Provide a stress suunary for the studs which compares the calculated stresses to the allowable stresses of Appendix XVII-2460 of the ASME Code when subjected to the combination of LOCA plus SSE loads.
Relate the basis for the calculated stresses to pump overspeed predictions. How will you verify that sufficient tension is applied to the studs throughout the plant life?
211.101 The response to Question 211.18 in Amendment A to the FSAR st.ates (5.2.2) that the pressuri:er code safety valves are designed for the following environmental conditions:
(1) 50 to 140 F (2) 0.5 to 2.5 psig (allowing for a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> test to 70 psig once per year).
The Midland FSAR (Section 6.2) shows containment environmental conditions well above these design conditions for a feedwater line break inside containment. Provide assurance that the pressurizer safety valves will operate when necessary to protect the RCPB, considering the environmental conditions which could exist during this event. Also, confirm that there are no other events in Chapter 15 for which the cressurizer safety val'ves are required to operate and the valves have not been cualified to more limiting environmental concitions.
211.102 NS-7154 of the ASME Code Section III states that:
"P ressure (5.2.2) relief devices, whose design is such that liquid can collect on the discharce side of the valve disk and such liquid could inter-fere with proper relieving operation shall be fitted with a drain at the lowest point where the liquid may collect." Describe how the pressuri:er safety valve discharge piping design satisfies this requirement.
211.102 Your response to Question 211.22, which describes your intention (5.2.21 to classify only one check valve in each LPI/CHR train as
".ategory AC, does not meet the staff requirements wi n res:ect to chec:< va:ve leak esting. The staff recuires that for every 2043 OM 6
211-19 (5.2.2) injection line in the DHR and E:~S systems (including such lines as auxiliary pressurizer spray} in which check valves nerform an
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isolation function, at least t>: check valves in each line be tested. To show that you meet these requirements, provide the following:
(1) A list of those valves which will be classified Category AC.
(2) Check valve testing schedule (3) Description of the test procedures and drawings of test con-nections. Include an estimate of test duration per valve.
(4). Leakage criteria to be included in Technical Specifications.
cn.104 Provide plant-specific drawings and descriptions for the pressuri:er (5.2.2) safety valves for the Midland plants. Describe all similarities or differences between these valves and the safety valves used on plants similar to Midland. Provide a description of each basic valve component and the valve manufacturer.
211.105 Branch Technical Position RSB 5-2 related to overpressure pro-(5.2.2) tection of PWRs while operating at low temperature has been recently approved by the Regulatory Requirements Review Comittee.
Staff question 211.8 addressed this position in anticipation of its approval. The position as approved is stated below with vertical lines to cannotate changes frem the original question.
Since Midland 1 and 2 are scheduled to receive operating licenses after March 14, 1979, compliance to the follcwing criteria is required prior to initial startup.
(1) A system should be designed and installed which will prevent exceeding the applicable Technical Scecifications and Accendix G limits for the reactor coolant system wnile operating at icw temperatures. The system should be capable of relieving pressure during all anticipated overpressurization events at a rate sufficient to satisfy the Technical Specification limits, particularly wnile the reactor coolant system is in a water-solid condition.
(2) The system must be able to perform its function assuming any single active component failure. Analyses using accrooriate calculational techniques must be provided wnich demonstrate that the system will provide the required relief cacacity assuming the most limiting single active failure. The cause for initiation of the event, e.g., c:erator er"JP, Com0Cnent malfunction, will not be considered as t.e single active failure. The analysis snould assume t.:e mest limiting a!':waaie ::erating c:nci:i:ns arc sys ams ::nfip. ati:n a-Ce ti~e Of !.9e OostulatSc 03use Of tre : Var ressure aven!.
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211-20 (5.2.2)
All potential overpressurization events must be considered when establishing the worst case event. Some events may be pre-vented by protective intericcks or by locking out power.
These events should be reviewed on an individual basis. If the interlock / power lockout is acceptable, it can be excluded from the analyses provided the centrols to prefent the event are in the plant Technical Specifications.
(3) The system must meet the design requirements of IEEE 279 (see implementation). The system may be manually enabled, however, the electrical instrumentation and control system must provide alarms to alert the operator to:
(a) properly enable the system at the correct plant condition during cooldown.
(b) indicate if a pressure transient is occurring.
(4)~ To assure operational readiness, the overpressure protection system must be tested in the following manner:
(a) A test must be performed to assure operability of the system electronics prior to each shutdown.
(b) A test for valve ocerability must, as a minimum be concucted as specified in the ASME Code Section XI.
(c) Subsequent to system, valve, or electronics maintenance, a test on that cortion(s) of the system must be performed to declaring the sys em operational.
(5) The system must meet the requirements of Regulatory Guide 1.25,
" Quality Group Classifications and Standards for Water,
Steam, and Radioactive-Waste-Containing Com:enents of.1uclear Power Plants" and Section III of the ASME Code.
(6) The overoressure protection system must be designed to function during an Operating Basis Earthcuake.
It must not compromise the design criteria of any other safety-grade system Wth which it would interface, such that the requirements of Rege.atory Guide 1.29, " Seismic Design Classification" are met.
(7) The overpressure protection system must not decend on -he l
availability of offsite power to perfom its function.
(S) Overpressure protection systems which take credit for an active comoonent(s) to mitigate the consecuences of an over-pressuri:ation event must incluce additional analyses consicering inadvertent system ini-iation/actuaticn or
- rovies justification to sncw nat existing analysas :cunc 3 6 C ?. In avent.
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211-21 (5.2.2)
We have reviewed your response to question 211.8 and request the following additional infomation:
(1) Figures 5.2-1 and 5.2-2 in the FSAR, which show the Appendix '
G curves for tJnits 1 and 2, are used to describe the adequacy of the Midland overpressure protection system. These curves do not completely reflect the Technical Specification curves' in the following areas:
(a) Significant differences exist between the cooldown limit curves in the Technical Specifications and the FSAR figures (Technical Specifications are more limiting).
This is especially significant for Unit 2, since this analysis is based on the heatup curve in FSAR Figure 5.2-2.
Using the Technical Specification curves, the pressurizer safety valves do got appear.to provide adequate protection above 320 F as stated in Section' 5.2.2.11 of the FSAR, since their set point is above the Appendix G limit.
(b) The FSAR figures do not show the more limiting pressure limits of tge Technical Specification. curves at temper-atures <190 F.
Your analysis does not address the pro-tection that would be required for these lower terperatures.
Address-each of these areas and correct or clarify your sucmittal accordingly.
(2) The Appendix G curves used as a basis for your overpressure protection system are based en the 5 SFPY material properties of the reactor vessels. Describe hew protection will be provided for the life of the plant.
(3) Provide your basis for stating that the HPI train initiation is the worst case event with resoect to Apcendix G.
Section 5.4.7.1.1.3 of the FSAR, which addresses overpressure protection of the OHR system, analyses the pressuri:er heater event as worst case (sce questica 211.11Q. Address this apparent discrepancy.
Inadequate discussion and analyses are provided to show that all pctential overpressurizr. tion events have been considered. For each of the events wnich are considered, provide your analytical basis for detemining the consequences.
Inclu.de all assumotions (such as steam generator - reactor ccolant temperature differential for the reactor coolant pumo start).
(a) Youg analysis assumes that the CHR system is cperational at 3C0 F.
It is not clear that this would be the case considering:
(a) The FSAR states ' na-ne ;hR systan for Miclano is nor ally initia ac at 2SC F D M ]o (P l0W he ahdFA 9/Ab 2043 092 6
211-22 (5.2.2)
(b) The design temperature of the DHR system is 300 F, 0
therefore no margin to this limit is available.
Address these two areas.
(5) Address the concern that the single failure of a power supply would prevent the operation of the power-operated relief valve and would also isolate the DHR relief valves due to closure of one isolation valve.
(6) Confusion exists in your submittal due to the differences between the Unit 1 and Unit 2 overpressure protection system designs. For example, no discussion or basis is provided for the difference between the DHR relief valve setpoints or the different power-operated relief valve low setpoint enabling temperatures for the two units. Clarify your sub-mittal to specifically address each difference and the reason for each. Provide a separate tabular listing for each unit similar to the existing combined list in the FSAR.
(7) You state in the FSAR that certain administrative controls such as lockout of power to one HPI train and the maximum operating pressurizer pressure and water level will be included in the unit operating procedures. The staff requires that any administrative controls which directly determine the. system design basis must be made a part of the unit Technical Specifications.
(S) Page 5.2-6c states that the PORV controls circui: is net IEEE-274 The staff position is that the GPS must meet IEEE-279. Discuss and justify all deviations.
(9) The use of operator action as a means of meeting the single failure criteria is not analyzed or discussed fcr Unit 2.
Provide this analysis. Provide or give reference for the DYSID computer code used for this analysis.
(10) The overpressure protection system must be designed to function during an operating Basis Earthquake (see paragraph 6 in acove BTP).
Confirm your design will meet this criteria.
(11) Provide and justify the DHR auto-closure set point pressure value.
R; vise other portions of tne FSAR to reflect this change.
(12)
'le recuire that the PORV operacility be tested in acccrdance with the recuirements of the ASME Code,Section XI. A test of only the electronics is not sufficient.
(13) Table 5.4-10 states that the CHR relief valves were oversi:ed to ac::=cda e liquid flashing. Provide your basis f:r si:ine taese valves as weil as the :ilet-c: era ac relief valve ::n-
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si,ering One flashing onenemenen.
- nc!;;e s:ecidi: al af la.Ve !ist Cata o su:Cor-nis basis f0F -:e range it s000i!i Os aniCn : ulo exis!.
211-23 (5.2.2)
(14) Confirm that the Appendix G curves (Technical Specifications) used as part of the design t, asis of this system are appropriate, considering the recent weld filler wire problem reported by similar 177 Fuei Assembly plants.
(See supplemental second round question 121.20.)
211.106 The response to question 211.33 does not provide sufficient
(,5. 2. 5 )
information for the staff to make an evaluation. The proposed alam(s) associated with the sump level monitoring system do not appear capable of alarming within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> given a 1 gpm leak.
Assuming a 1 gpm leak with the proposed system, a high level sump alam could take as long as 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to alarm assuming the sump is empty when the leak initiates. Revise your design to provide the capability to alarm within the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> limit.
211.107 The response to question 211.24, which states that the core flood (5.2.5) tanks, decay heat removal, HPI, nitrogen and vent and drain systems have been deleted as potential points of intersystem leakage because each is sufficiently isolated from the reactor coolant system does not meet the intent of Regulatory Guide 1.45.
Regulatory Guide 1.45, par. C.4. states that:
" Provisions should be made to monitor systems connected to the RCPB for signs of intersystem leake.ge."
Although isolation valves and/or check valves are provided for these systems, we require that methods be ::rovided to monitor the integrity of these isolation features.
211.108 Provide a diagram (.s) of the reactor building sump leakage detection (5.2.5) system (sump, purrps, detectors, etc.) showing the relative lecc:fon in the reactor building. Confirm that the leakage detection sump will not interfere with the correct performance of the recirculation sump (since it appears that the two sumps nay be the same) con-sidering the collection of dirt and debris due to normal leakage.
Such a discussion should include the effects of sand, dirt, etc.,
en pump bearings, machined surfaces, etc.
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211-24 211.109 The response to question 211.34 is not complete. Discuss how you (5.2.5) intend to calibrate the airborne radiation monitors to the known system leakage levels.
211.110 The infomation provided in the response to question 211.38 is (5.4.7) not sufficient to allow the staff to make an adequate detemination.
The Midland FSAR states that the relief valve on the decay heat removal system pump suction is sized to provide the required pressurizer outflow rate resulting from energizing pressurizer heaters. Provide the initial conditions for your calculation of the pressurizer outflow rate for this event and justify their conservatism. Table 5.4-10 incicates that the relief valve is rated at 1844 gpm 010% accumulation. Provide assurance through data or testing of similar valves, the effect of flashing in the valve throat has been considered and that the 1844 g;m rating is for the relief of liquid at 400 psi.
It is not t! ear why the pressurizer heater event would be worse.than the start of one or more hign presnre injection pumps. nacress all potential events of this type in nur response. The response to question 211.38 (Section 5.4.7... 3) infers that only one DHR relief valve is available while te P+ID in Figure 5.4-11 and Section 5.2.2 show and address two valves in the letdown line. Address this discrepancy.
211.111 The relief valves on the suction of the DHR pumps are set to (5.4.7) relieve at 400 psig. Considering the DHk jump shutoff head of approximately 200 psig, confirm that the pumo discharge piping would remain less than 110% of system design. Address this concern considering:
(1) the worst case pressure transient (2) the pump head (3) heat exchanger and valve pressure crops (a) relief valve locations and set points.
211.112 The Midland FSAR states that, "the pressurizer heaters and (5.4.7) pressurizer heater controls are necessary if hot shutcown is to be maintained for an extended period of time, but are not imediately necessary to establish or maintain safe shutdown."
Sufficient justification is not provided in the FSAR to support the design adequacy of the nonsafety-grade pressurizer heatars.
We require that:
(1) A safety-grade bank of heaters be provided to perform the pressure control function, or (2) A discussion be provided of hcw the plant will be snut town assuming no pressuri:er heaters available,(hot shu nown pro-ceecing to cold snu cown).
are na ural circulation anc
- orati:n test recuirec in 0211.25 must be conductec wi-hcu-tne use of pressuri:er heaters.
20 0 095
211-25 211.113 The response to question 211.14 states that the contribution of (5.4.7) the low flow DHR pump interlock to the probability of a complete loss of low pressure injection is " insignificant." Your basis for this conclusion is that the low flow trip is interlocked to the ECCAS signal such that the ECCAS signal to the DHR pump would override the pump trip signal, and that the redundancy of the CHR system and this circuitry prevents a loss of all low pressure injection flow even with a single failure. You state that this feature is necessary to prevent pump damage due to closure of a.
suction valve in the single drop line. While this feature would be desirable from the DHR availability standpoint, it could provide an adverse effect on the overall unreliability of the ECCS, even if the single failure criterion is met. Our position is that you have not provided adequate justification for the necessity of the loss of flow trip feature. To more carefully evaluate its desirability, the following information is necessary:
(1) The basis for 900 gpm flow set point which would generate the trip is not apparent. Provide the basis for using flow rather than alternative methods to generate the trip.
Discuss the disadvantages of alternate methods (limit switches, pressure,etc.) Also address the desirability of alternative measures which would not affect ECCS reliability, such as continued recirculation through the heat exchanger and recirculation line.
(2) Determine, using probabilistic event tree methods (NASH-14CO, Reactor Safety Study), the overall effect on ECCS reliability caused by using this trip feature. Provide a basis for all assumptions.
(3) Compare both the effect of this feature on ECCS reliability with the potential for failure of the CHR system with and without the feature (with res;:ect to their effect on the overall proMbility of core melt). Provice your conclusions regarding these analyses.
211.114 Your resconse to question 211.54 does not provide sufficient (5.3) infomation for the staff to make an evaluation of the LPI pump r* liability. The following information is necessary to justify reference of the LPI pump performance at other 177 FA plants:
(1) Provide a cescription of the Midland L?I pumps to include:
(a) manufacturer (b) type (stages, bearing cooling requirements, lube oil cooling requirements, etc.)
(c) comconent materials (shaft, bearings, etc.).
2043 096 O
211-26 (6.3)
(2) Describe any significant differences between the Midland LPI pumps and those at similar plants. For any difference, describe the effect it will have on the pump long-term reliability.
(3) Your response only discusses the normal shutdown functic'1 of the LPI pumps. Also address the following:
(a) Justify your reference to pump operation during normal conditions to confirm post-LOCA long-tem reliability since operation during accident conditions could be considerably different (temperature, chemistry, debris, etc.).
If the conditions are not the same (normal shutdown cooling vs post-LOCA long-term cooling), what is the technical basis for assuming they have no effect on long-term pump performance?
(b) Did the previous operational experience include continuous operatien of the pump for the length of time that would be required of the pump in a post-LOCA situation?
(c) If the previous operation was not continuous, was maintenance performed between pump runs? If maint* nance was performed, could that same maintenance be conducted
-- in the post-t0CA situation considering thr high radiation fields and temperatures expectec
211.115 Page 6.3-2 states that the ECCS design is " equivalent" to other (6.3) ccerating 177 FA lowered loco plants. Mcwever, the FSAR else-where incicates that automatic trio:; of HPI pumps and LPI pumos for certain signals are incorporated in the Midlanc design. There-fare, identify all significant differences between the Midland emergency core cooling system and the emergency core cooling systems of previously licensec 177 fuel assembly lowered loop plants. Justify the impact of these cifferences on overall system reliability. Also, correct the numeer of LPI pumps for Pancho Seco in Table 1.3-1.
211.116 The respense to question 211.5 does not provide a reference tu (5.3) an approved LOCA calcu'ation for the Midland units. Letters dated May 12, 1978 and July 13, 1978 from S. H. Hcwell (Censumers Pcwer Comoany) to J. G. Keppler (USilRC) are interim reports which discuss tne small break calculation deficiency which exists.
It is cur desire to minimi:e any reliance on the coerator to align the HPI system following a small break and, therefore, agree with tne apolicant's pursuit cf a design mcaificaticn wnicn will serve this objective. The fcilowing information is recuired:
2043 097 6
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211-27 (6.3)
(1) Revise ECCS small break spectrum analysis using an approved model.
(2) Justification for any design change which must address the overall impact of the change on plant safety as well as the need and intent of the change.
211.117 The response to question 211.10 does not adequately address the (6.3) staff's concern considering the small break discrepancy in the BAW-10103 small break calculations (see question 211.116). The HPI line break discussion may not be appropriate if a crossover line modification is installed. Also, it has not been demonstrated that 20 minutes to perform the required manual action is available to the operator. Provide the following:
(1) Discussion of single failures considered (i.e., break in one train, single failure of HPI pump in the other).
(2) Method of analysis to confirm that 20 minutes will be available.
(3) Specific actions needed 211.118 The response to question 211.5 does not provide sufficient (6.3) information for the staff to make an adequate evaluation. With regard to your NPSH calculation and assumptions, provide the following parameters used in your calculation to show that the required NPSH is assured and that the Regulatory Guide 1.1 assumptions are used:
Injection from BWST (1) HPI pump centerline elevation (2) LPI pump centerline elevation (3) Basis for 11.75 ft BWST water ievel (4)* Basis for 250 gpm HPI ficw (5)* Sasis for 3000 gpm LPI flow (6)* Piping lesses in HPI path (7)* Piping losses in LPI path (8) SWST elevation and pressure 2043 098 o
211-28 (6.3)
Injection from the Recirculation Sumo (1) Recirculation sump water level--(is all injected water frem BWST available; what amount is trapped and does not reach sump't).
(2)* Total head loss in recirculation path (U* Flows assumed and basis
- The pioing loss calculation must assume conservative flows (run-out) in the appropriate portions of the system. For example, the FSAR states that 3,000 gpm LPI flow is assumed during recirculation.
This does not appear to be conservative since the reactor building spray pumps also take a suction from the sump.
211.119 The Midland FSAR references BAW-10103 for the LOCA break spectrum.
(6.3)
The reactor vessel flow assumed in BAW-10103 is 38,306 lbm/sec (Table 4-1).
The Midland FSAR (Table 1.3-1) indicates that total reactor vessel flow for the Midland units will be 126.3 x 106 lbm/sec (35,083 lbm/sec), which suggests that the LOCA analyses in BAW-10103 are nonconservative. Correct this discrepancy, or provide the following:
(1) Appropriate LOCA analyses using the correct flow rate, or (2) Justify the conservatism in BAW-10103 through sensitivity studies.
BAW-10103 Table 4-1 also indicates that the reactor vessel flow for Unit 1 and Unit 2 differs (Unit 1 - 39,193 lbm/sec; Unit 2 -
40,105 lbm/sec), while the Midland FSAR indicates that bcth units are the same in this area. Clarify this area and discuss tne variance with Table 1.3-1.
211.120 Paragraph 6.3.3.10 of the FSAR states that the whole-core hydrogen (5.3) generation is calculated to be 0.557';. This is not correct and should be changed to 0.647% (see BAW-10103). This value (0.647';)
is a result of B&W calculations using an adiabatic heating assumotion during the steam cooling pericd when the core reflood
. rate is less than 1 inen per second.
211.121 The SCCAS opens the BWST HPI suction valves and shuts the :akeuo (5.3) tank isolation valves. Provice assurance that tne closure / opening times of these valves are coordinated such that HPI pumo damage will not result due to loss of suction. With regard to the potential for water hammer (cuestion 211.41), it is our cosition the BWST suction should rerain open to botn L?I and HPI, unless suitably justified.
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211-29 211.122 The Midland ECCS utilizes a recirculation activation system which, (6.3) upon generation of the ECCAS and BWST low level signals:
(1) stops the HPI pumps; (2) opens the sump isolation valves;
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(3) shuts the BWST isolation valves.
Also, the FSAR states that the operator, when shifting to the
" piggyback" mode of operation for small breaks will:
(1) cross connect LPI to HPI suction, and (2) block the RAS (recirculation signal to the HPI pumps).
It is not clear why the RAS signal to stop the HPI pumps is necessary considering the time which should be available to the operator for small breaks. Justify this portion of your design.
When the RAS signal is blocked, would not the shift to the sump have to be made manually? Discuss the difference in the Midland ECCS design in this area with similar 177 FA. lowered loop plants and justify these differences in terms of overall system reliability.
Also, include in your discussion the need for auto closure of the BWST suction valves by the RAS.
211.123 Section 6.3.2.8 of the FSAR states that the operator will determine (6.3) if piggyback operation is required by LPI flow rate indication of less than 750 gpm. Address how this indication by itself is sufficient to serve as a basis for the operator's decision, since problems such as inadequate pump suction head could account for lower flows. Discuss other indications, for examcle, how reactor pressure would enter into the operator's decision to shift to piggyback operation and whether emergency procedures address this aspect of the need for piggyback operation.
211.124 Discuss the safety design basis for the recirculation activation (5.3) signal actuating the HPI lube oil pumps.
211.125 The response to question 211.89 does not provide sufficient (5.3) information for the staff to make an adequate evaluation. Your response does not address consideration of the displacement of water by ecuipment when calculating maximum water level. Show that your calculation accounts for this increase in level (considering the as-built design).
Our position with respect to the motor operatort for the valves in the duro-to-sumo lines is that they should be 1ccated abcVe the maximum post-LOCA water level, or that adecuate protec ion
- ust be provided.
2043 100 6
211-30 (5.3)
The DHR metor-operated suction valves inside containment will be 7 feet below the maximum calculated water level post-LOCA and protection is not provided. Address the need for long-term post -
LOCA recovery and the necessity of having these valves available to perform this evolution.
211.125 The response to question 211.56 dcas not adequately meet the (5.3) stafi":; criteria for the prevention of excessive baron precipitation during post-LOCA long-term cooling. Our position is that the operator be provided with flow indication to confinn that the minimum required dilution flow exists. We do not consider an "open" indication on the dump-to-sump valves a positive means of determining adequate flow.
With regard to the preoperational test to demonstrate the minimum flow capability, submit the test procedure to be employed.
Include a basis for the procedures and quantities addressed, such as " design value hot leg water level."
211.127 Table 6.3-2 indicates that an ECCAS signal causes the LpI line (5.3) isolation vcives to open. The table shculd be changed to indicate that these valves are locked open with power removed (consistent with Technical Specifications).
211.122 Your re'spense to question 211.51 is not complete. Verify that (5.3) there is no one manual valve which could interrupt the flow to both ECCS trains.
211.129 Your response to question 211.58 is not adequate. We require (5.3) that positive means be provided to prevent icing of the BWST vent.
Considering the location of the BWST (outdcors, in a northern climate), it is not clear how oversizing of the vent would adecuately prevent blockage. There still exists the potential for large snow accumulation and ice buildup over a 10-inch line.
It is our position that a more positive alternative be preposed to reduce the potential for inadequate ECCS delivery during a LOCA. Also, justify not including heat tracing on the vent and discuss the vent configuration.
211.130 Provide ju-tification for referencing the First-of-a-Kind Oconee (5.3) core flood tank fic9 rate test. Justification must include your plans to ensure similar piping characteristics in the Midland as-built design.
provide a discussion of similarity of valve resistances, etc.
211.131 The res::ense to cuestion 211.47 does not provide sufficient (5.3) infomation for the staff to make an evaluation. The fellcwing (5.2.7) information is necessary to determine the acceotabil~ity of the Midland plant with respect to post-LOCA passive failures:
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211-31 (6.3)
(1) Provide your basis (data) for assuming a 10 gpm CHR punp (5.2.7) seal leak as a " representative" leak.
Is this a worst case?
(2) Section 3.4.2.2 states that a 10 minuta delay is assumed for those situations that involve operator action in the cortrol room. Our position is that a 30 minute delay must be assumed.
(3) Discuss your leak detection system in the auxiliary building and show how it meets the requirements as stated in question 211.47, paragraphs 3, 4, and 5.
211.132 Table B-1, BAW-10103, states that the containment spray system (6.3) delay time assumed in the LOCA analysis is 65 seconds and also states that the Midland containment spray delay time is 35 seconds.
The shorter delay time in Midland would tend to reduce containment pressure and is, therefoN, not conservative for the LOCA calculation. Address this concern with respect to the minimum containment pressure calculation used in the Midland ECCS analysis, and justify your reference of the BAW-10103 analysis.
-211.133 Table 6.3-6, Failure Modes and Effects Analysis, refers to the (6.3)
LPI line throttle valves, but no valve numbers are given. What valves are used to throttle LPI flow? Confirm that no ficw throttling is required by the operator post-LOCA. Discuss the necessity of these valves, since similar 177 FA plants (Crystal River 3) do not have them.
211.134 The response to question 211.41 does not satisfactorily address (6.3.2.5) the concern for proper ECCS filling and venting. The response states that the methods will be addressed in the individual operating procedures for the systems in the ECCS. We will require that periodic verification of fully vented ECCS piping and pump casings be included in the Midland Technical Specifications.
211.135 Provide drawings showing the containment sump, the reactor (6.3) building, the areas which will become ficoded post-LOCA, and the path by which the water will reach the sump.
211.136 The response to question 211.12 does not address the consequences (None) of a break in the normally pressuri:ed makeup line, but addresses a break in a high pressure injection line. Provide a response to this cuestion considering the information requested in questien 211.83 for breaks in high energy piping.
211.147 License event reports frem plants similar to the Midland units (15.0) indicate that current B&W recor= ended operating procedures require flooding of the feecwater no::les of the one-tnrcugh-steam-genera or at low cower levels (<5%) to prevent long-term feecwater ne::le thermal degradation due to themal shcck. The staam line break 2043 102
211-32 (15.0) analysis (and presumably all other accident analyses) in the Midland FSAR assume minimum steam generator inventory at low power levels, while the above indicates that this would not be the case.
If this operating procedure is applicable to the Midland units, provide assurance that the input assumptions and sensitivity studies for Chapter 15 accident analyses remain valid.
211.138 Burnable poison rod assembly and orifice rod assembly modiff-(15.0) cations have been conducted on plants similar to Midland (Crystal River 3 and Davis Besse 1). Should this modification be made on the Midland units, additional analyses will be recuired to address the effects of the core flow and nuclear parameter changes on the Chapter 15 analysis. Provide complete documentation of the Consumers Power evaluation of this area of concern.
211.139 Discuss how tha analyses in Chapter 15 provide a basis for (15.0) partial ' loop operation (3 reactor coolant pumps) of the Midland units.
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211-33 211.140 Figure 15.0-2 shows the " Percent Control Rod Worth vs. Percent (15.0)
Control Rod Insertion Applicable to all Accidents Analyzed" for the Midland units. The rod worth as shown on this curve does not appear to be conservative with respect to the rod worth data for Oconee 2 and SMUD reported in the response to question 212.71 on the BSAR-205 docket. Show.how this data, or any other appropriate data, is reflected in the rod wvths assumed for the Chapter 15 accident analyses. Specifically address the control rod travel time to 2/3 insartion of 1.4 seconds assumed in the accident analyses (Table 15.0-2) and show that this time conserva-tively provides an adequate reactivity insertion rate with respect to the operating plant data.
211.141 The worst case increase in feedwater flow event assumes the full (Table opening of one feedwater control valve. Confirm that the ICS 15.01-1) could not open more than one valve, given a single initiating failure. Confirm that the opening of both feedwater control valves would not have to be considered as a moderate frequency event. Alternatively, confirm that operating history supports the Midland assumption.
211.142 The response to question 211.60 is not complete, since it only (15.0) specifically addresses the turbine analysis with respect to assumations regarding non-safety grade equipment. An example of another event would be the decrease in feedwater temperature event which shows an increase in reactor coolant system pressure at 30 seconds wnen the reactor trips. The would acoear to be the result of the turbine trip via CRDCS signal (which is non safety grade) and would lend a non-conservative factor to the resulting MONBR. Our pcsition is that no credit for non-safety grade equipment may be assumed for Chapter 15 events unless suitably justified. Show that all transient analyses for the Midland units conform to this position. Revise Tacle 15.0-4 or provide a new table to show wnat systems are "given credit" for correct operation in the mitigation of each Chapter 15 event.
0 211.143 What is the basis for selecting an 85 F decrease in feedwater (15.1 )
temperature for the decrease in feedwater temperature moderate frequency event? Provide assurar:e that this decrease in temaer-ature would bound any anticipated feedwater heater or ICS failure which could cause such an event.
211.122 With regard to the steam line break analysis, wny is auxiliary feedwater assumed to flow to the unaffected steam generator at 16.7 seconds for the worst case DNS event and 35.5 seconds for tne worst case overcooling event?
211.145 Jescribs the signal that trios the turoine s:cp valves for :he (15.2.5) less of AC power to the station auxiliaries.
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211-34 211.146 With respect to the loss of normal feedwater event in Section (15.2.7) 15.2.7, address the following,
(1) The parameter sensitivity stydy in Appendix 15C, Supplemental Feedwater Break Accident Analysis, concludes that the event initiated at higher powers is not the worst case due to the larger OTSG inventory and the resultant larger cooling effects. Apply this consideration to the loss of normal feedwater event and justify that you have analyzed the worst case.
(2) As an upset event which must be considered in the overpressure protection of the RCPB as required by the ASME Code Section III, this event should be included in the ASME Code required Over-pressure Protection Report. It is noted that " credit" is taken for the Doppler and Moderator reactivity feedback in the FSAR analysis while no credit is taken in BAW-10043.
Discuss this inconsistency.
211.147 The Midland FSAR refereaces BAW-lC043 for the turbine trio (15.2) without bypass event. The following questions apply to this topical report:
(1) Justify the-reference of t iis topical report as appropriate for the Midland plant since no initial conditions are given in the topical report (power level, flow, etc.).
(2) We require that the overpressure calculation must assume that the reactor scram is initiated by the second safety grade signal for the reactor protection system. SAW-10043 assumes a trio on the first RPS signal and is therefore not acceptable. Provide an analysis meeting this recuire-ment.
(3) 2AW-lC043 states that the loss of feedwater flew and complete loss of power events are considered, yet no analytical results are cited. Provide these results.
(4) The Midland FSAR provides analyses wnich result in ;eak RCS pressures higher than those stated in 3AW-10043. This indicates that SAW-10043 is not conservative. Address this discrepancy.
(5) ?rovide or reference the cotouter model(s) used for the 5AW-10043 calculations.
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~
211-35 211.148 The Midland FSAR does not provide or reference an analysis of (15.3) a loss of reactor coolant flow due to an offsite power system frequency decay. Provide the following infomation:
(1) A bounding curve of frequency decay rate as a function of time for which DNBR will not be less than 1.30.
(2) The maximum frequency decay rate expected for the Midland units.
211.149 For the locked rotor event, the staff criteria for fuel failure (15.3) is MDNBR <l.30, rather than the hot spot fuel cladding surface temperature. Therefore, to show that the consequences of this event do not produce unacceptable dose consecuences, provide the precentage of fuel pins which would experience a DNBR <1.30.
211.150 The Midland FSAR provides loss of reactor coolant flow analyses (15. 3.1 ) for the four, three, and two reactor coolant pump operating conditions. Provide the one pump coastdown analysis for the four pump case showing that the MONER criteria is met.
211.152 For the refueling case, the FSAR states that assuming an initial (15.4.5) 5% shutdown margin, emptying a makeup tank into the reactor vessel with no head on results in a.54% subcriticality margin.
Page -15.4-24 of the FSAR states that it is assumed that dilute water is supplied to the makeup tank by other pumps such that it never empties. Considering this design aspect, it is not clear that the operator would have 30 minutes frem the time an alarm makes him aware of the event to the loss of shutdown margin (Standard Review Plan 15.4.5). Provide an analysis which meets these requirements.
211.152 The Chapter 15 moderator dilution analyses assume operator action (15.a.5) based on a high makeup ficw alam. Provide a discussion of.this alam consisting of:
(1) location and type of sensor (s)
(2) indication units and instrument range (3) alam set point and uncertainty Address the concern that dilution events could occur at rates less than 300 gpm which would not be detected by the makeuo flow alarm. Since this alarm is used as a safety related indicator, it must meet safety grade requirements (i.e.,
seismic category I and IEEE-279).
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211-35 211.153 Review of the three feedwater line break cases with respect (15C) to MDNBR indicates that the worst c:se may not have been analyzed: EOL, maximum steam generator inventory, loss of offsite power after rupture (see fig.15C-ll; Table 15C-16).
Provide an additional calculation of this event sequence or a complete justification of why the current analysis bounds this event.
211.154 The Midland FSAR states that Figures 150-16 through 18 and (150) 150-14 show the system response for the 36" double ended rupture mainsteam line break, yet the Figures indicate that they are for the 33.5" piping rupture. Table 15D-13 indicates that the 36" break which should be the worst case break was not analyzed. Clarify this discrepancy and confirm that the worst case mainsteam line break has been analyzed with respect to DNB.
Consider a 36" steam line rupture outside containment and also address a steam line break in the 36" line to the process steam system.
211.155 Section 15.1.5, which describes the worst case mainsteam line (15.1.5) break, states that the offsite power available case provided essentially the same results (1.25% pins in DNB) as the loss of offsite pcwer at rupture case. Table 15D-13 lists the results for the various MSL3's analyzed for different conditions and indicates tha? +.he DNB results of the power available case were not calculated. Justify your statement that the loss of offsite power case at rupture is worse.
211.156 How were the affects of steam generator fouling over the life of (15.1.5 ) the plant considered in determining the worst case mainsteam line break.
211.157 The mainsteam line break parameter study does not include an (ifD) analysis of how the worst case single failure was determined (MSIV, FWIV, Atmospheric Dumo Valve, etc.). provide a complete analysis to show that the worst case single failure has been considered.
Page 15.1-9 on the FSAR states that the single active failure of an MSIV is not credible. The staff does not concur with this position sinc operational exterience has shewn that valve and valve actuator problems can occur which can prevent full closure of these valves. Therefore, consideratien of MSIV single failures must be included in your analysis.
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211-37 211.158 Justify not considering the effects of RC pump status and turbine
~
(15D) trip in the worst case main steam line break parameter study (with respect to DNB).
211.159 Address the following areas concerning the process steam system:
(150)
(1) Section 6 on page 15D-4 of the supplemental steam line break analysis states that, "the process steam plant, when connected, helps keep the pressures up in the secondary system." Provide a discussion to support this statement and describe the role of the " process steam system" during the main steam line break event.
The need for this system to mitigate the consequences of this accident should be clarified.
(2) Considering an assumed main steam line break between a steam generator and a MSIV, and a postulated single active failure of the MSIV on the other steam generator, both steam generators would blowdown since no automatic isolation is provided to the process steam system.
Address this scenario.
(3) Describe the safety significance of the second set of MSIV's on the Unit 1 OTSG steam lines and how they are assumed to function during a main steam line break.
211.160 Figure 10.3-1 shows additional main steam isolation valves in (None) the steam lines for Unit 1 and not for Unit 2.
Discuss the rationale for this inconsistency and the overall impact on Chapter 15 analyses. The latter discussion should include a comparative risk aosessment between Units 1 and 2, with a probabilistic evaluation of the relative difference the MSIVs provide in accident mitigation. Discuss the potential for a steam line break in the process steam cross connec: line such that the event (in addition to the single failure of one cross connect valve) would result in a blowdown of the steam generators of both units (2 steam Scnerators for each unit).
211.161 Your response to question 211.11, which dis usses operator (15E.7) actions following a steam line break, does not adequately address the staff's concern. Provide the following information with respect to reactor coolant inventory control foliowing a main steam line break:*
(1) Identify the specific actions necessary to maintain pressuri:er level (with or without offsite ;cwer available).
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211-38 (15E.7)
(2) Specify the time available to prevent HPI pumps from filling the pressurizer and causing pressure to increase to the safety valve set point.
(3) Confirm that reactor coolant sy. tem pressure and temperature would not cause a violation of Appendix G limits, or show that vessel integrity is assured by fracture mechanics calcub Mons.
zii.i62 ins ;;*! 'Sut? awn Systems Operating Sequence diagram does not (15E.36) conform to the shutdown criteria in question 211.35. Provide an additional diagram considering the requirements of this questiun.
211.163 The response to question 211.11 in the area of long term cooling (15E) following a steamlina creak is not complete. Discuss the methods available to provice continued long term cooling following a main steamline break. Confirm that no equipment necessary to provic:e this capability will be made unavailable due to sub-mergerce inside containment as a result of containment spray and the fluid exiting the break (assuming a break inside containment). Address the need for the availability of the DHR system as a means to provide long term cooling since the OHR dFop line motor operated valves inside containment are not submergence p otected.
211.164 It is not clear how the inadvertent closure of a main steam (15.2.4) isolation valve (MSIV) is bounded by the loss-of-normal-feedwater event considering the ass > metric core temoerature distributions which would result when one MSIV is shut. Provide an analysis to address this concern.
211.165 This table states that the inital temoeratu5e (PCS inlet) at (Table rated power assumed for all analyses is 555 F.
The plant 15.0-2)
Techn; cal Specifications allow operation at power as low as o
TAVE 525 F.
Provide a justification for your assumption of f
initial RCS temoerature for all Chaoter 15 events, considering the range of RCS inlet tamceratures allcwed by the Tecnnical Speci fications. Discuss the normal RCS temoerature program and the potential for operating at various temoeratures.
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