ML20213C847
| ML20213C847 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf, Susquehanna, Columbia, 05000000 |
| Issue date: | 01/12/1979 |
| From: | Mazetis G Office of Nuclear Reactor Regulation |
| To: | Stolz J Office of Nuclear Reactor Regulation |
| References | |
| CON-WNP-0251, CON-WNP-251 NUDOCS 7901230319 | |
| Download: ML20213C847 (15) | |
Text
8 a 4 UNITED STATES
[" t NUCLEAR REGULATORY COMMISSION WASHINGTON, D. C. 20555
[
Docket No.s. 50-397 50-387/388 50-416/417 MEMORANDUM FOR: J. F. Stolz, Chief, Light Water Reactors Branch No. 1, DPM
- 0. D. Parr, Chief, Light Water Reactors Branch No. 3, DPM S. A. Varga, Chief, Light Water Reactors Branch No. 4, DPM THRU:
T. M. Novak, Chief, Reactor Systems Branch, DS Q t Y FROM: G. R. Mazetis, Section Leader, Reactor Systems Branch, DSS
SUBJECT:
REVIEW 0F WPPSS NUCLEAR PROJECT NO. 2, SUSQUEHANNA UNITS 1 AND 2, AND GRAND GULF UNITS 1 AND 2 - ROUND ONE QUESTIONS Plant Names: WPPSS-2 Susquehanna Grand Gulf Docket Numbers: 50-397 50-387/388 50-416/417 Milestone Number: 05-21 05-21 05-21 Licensing Stage: 0L OL OL Responsible Branch LWR-4 . LWR-3 LWR-1 and Project Manager: D. Lynch S. Miner C. Thomas Systems Safety Branch Involved: RSB RSB R,SB Description of Review: Q-1 Q-1 Q-1 Requested Completion Date: Jan. 5, 1979 Jan. 5, 1979 Jan. 5, 1979 Review Status: Incomplete Incomplete Incomplete The Reactor Systems Branch has consolidated the reviews of the above three
. plants. As discussed in previous correspondence, enclosed is the first set of Round One questions. We have reviewed the information contained in the FSAR Sections 3.5.1, 4.6, 5.2.5, 5.4.1, 5.4.6, 5.4.7, and 5.5.2, including secondary review areas of Section 7.6 through Amendments 1, 3, and 26 of WPPSS Nuclear Project No. 2. Susquehanna Units 1 and 2, and Grand Gulf Units 1 and 2, respectively. Please note that the format of the submitted questions does not follow the numbering sequence subsequent to the original questions from the acceptance review. This consolidation of questions was used to expedite transmittal to your office. Margin notations were made to identify plant applicability. We are available should further clarification be necessary.
y ( .YC '
Contact:
Al Ignatonis, NRR 49-27341 ,,
I 7 9 012 3 0 311k i
~,
J. F. Stolz, et al. JAN 12 579 The remaining portion of our Round One questions is currently planned to be forwarded by February 20, 1979. This portion will primarily consist of our review of Sections 5.2.2, 6.3, and Chapter 15 of the FSAR. Our assistance with staff review of the Technical Specifications is awaiting DPM distribution and discussion of the proposed Technical Specifications.
Gerald R. M. e , Section Leader Reactor Systems Branch Division of Systems Safety
Enclosure:
Round One Questions cc: R. Mattson R. Tedesco D. Vassallo D. Lynch S. Miner C. Thomas T. Novak S. Israel G. Mazetis R. Frahm A. Ignatonis C. Graves B. Siegel
211-1 ROUND ONE QUESTIONS FOR GRAND GULF, WNP-2, AND SSES 211.0 REACTOR SYSTEMS BRANCH 211.1 With regard to the floor drain sump level monitoring systems, GG (5.2.5) discuss sump geometry, leakage flow rate mesurement accuracy, WNP-2 (7.6.1.4) measurement (monitoring) interval, and other information relevant (9.3.3) to demonstrating a sensitivity of 1 gpm per hour.
211.2 Provide a list of normal and maximum expected leakage rates and SSES (5.2.5) activity concentrations from identified and unidentified sources (9.3.3) (e.g., CRD flange leaks, vent cooler drains, etc.) that are directed to the drain sumps.
211.3 The drywell equipment drain sump receives two types of reactor GG (5.2.5) coolant leakage--hot and cold. Leakage from " hot" sources such SSES as the reactor vessel head flange, vent drain, and valve packings WNP-2 may flash into steam which must be condensed to reach the sump.
What assurance is there that the steam will be condensed for leak detection monitoring purposes? For leakage from " cold" sources, the floor drain system is employed. Thus, the floor drain system should be tested periodically for blocked lines. Discuss the surveillance program planned to minimize the potential for drain system blockage.'
211.4 In conformance with Regulatory Guide 1.45, the radioactivity GG (5.2.5) monitoring channels are stated to be qualified for operation SSES (7.6.2.4) following an SSE. Confirm that all of the remaining leakage WNP-2 detection methods (systems) are qualified for operation following an OBE, (This includes the drywell equipment and the floor drain sumps, sump coolers, and associated instrumentation and piping.)
211.5 With regard to the censitivity and response times of the contain-GG (5.2.5) ment airborne radiation monitoring systems, provide a detailed SSES (7.6.2.4) discussion on the capability of these monitors to detect a 1 gpm WNP-2 (12.3.4) leak in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> for varying containment background activity levels.
The background activity levels should be considered for the plant containing fresh, irradiated, and permissible amounts of failed fuel, and the presence of normal expected leakage rates. Al so ,
include the assumptions used in determining response times, such as the preset alarm level for higher background leakage and the plateout factor. [ Note that in Section 7.6.lb no information has been provided regarding sensitivity and response times, and reliability of the airborne radioactivity monitoring systems as was stated to be in Section 5.2.5.1.2.3.]*
[ ]* add to SSES only.
211-2 211.6 Clarify that the calibration of the level sensors is performed SSES ( 5. 2. 5.1-) during nomal plant operation. Note that per SRP 5.2.5, the leakage detection systems should be equipped with provisions
- to pemit calibration and operability tests during plant operation.
Also, the testing and calibration should be in compliance with IEEE Standard 279-1971. Discuss how you intend to comply with the above requirements.
211.7 Expand your discussion on how the means of correlation with di .
GG (7.6.2.4) verse monitoring methods will be used for leakage detection system WNP-2 operability verification and calibration. For example, if a radioactivity monitoring system is checked against the sump level and flow monitoring system, how is the latter system found to be acceptable for accuracy? Secondly, confim that calibration and operability tests will be perfomed during plant operation and in compliance with IEEE Standard 279-1971.
211.8 Section 5.2.5.1.2.4.1 and Figure 9.3-11 indicate that the drywell SSES (5.2.5.1) floor drain sumps collect overflow from the drywell equipment drain tank in which the latter is used for collection of uniden-tified leakage. This type of design feature appears to preclude separate monitoring of identified and unidentified leakage.
Show what measures will be taken to prevent a small unidentified leakage that is of concern from being masked by a larger acceptable identified leakage.
211.9 Provide leakage detection system drawings M-1090A and M-1090B.
GG (5.2.5) 211.10 Table 5.2-9 shows RCIC isolation function for the variable moni-GG (5.2.5.1) tor of reactor low water. Verify if this is an error.
211.11 You state that major components within the drywell which are GG (5.2.5) sources of leakage by nature of their design (e.g., sump seals, WNP-2 (7.6.1.4) equipment waming drains) are contained valvestempackirphpmentdrainsumpandtherebyidentifie:1.
and piped to an e Clarify the term " sump seals." Discuss what monitors are available to the operator to identify the source of leakage between such components as the sump (or pump) seals and the equipment waming drains and all other component sources cirained to the drywell equipment drain tank. Clarify if there are any sumps within the drywell which must be filled before sump drain flow occurs to the equipment drain tank.
, 211-3 211.12 Explain why the piping from the valve stem packing leakoff con .
SSES (5.2.5.2) nections (of the power-operated valves in the HPCI, CS, RCIC, RHR, etc.) to the equipmant drain sump contain normally closed manual valves. Shouldn't these valves be nonnally opened?
211.13 Explain the purpose of locating the 3/4-inch piping to leak GG (5.2.5) detection system downstream of the testable RHR check valves F041A, F041B, and F241 (see drawings M-1085A & 8). The same question also applies to the LPCS and HPCS designs (see drawings M-1086 and M-1087).
211.14 In confonnance to Regulatory Guide 1.45 you state that provisions GG (5.2.5) will be made to monitor systems connected to the RCPB for signs SSES (7.6.2.4) of intersystem leskage. Provide a detail discussion that includes WNP-2 identification of all potential intersysten leakage paths (in-cluding detecting leakage from primary coolant system to the RHR an.d ECCS injection line) and the instrumentation used in each path to provide positive indication of intersystem leakage in the affected system.
211.15 BWR operating experience has shown that the HPCI and RCIC systems GG (5.2.5) have been rendered inoperable because of inadvertent leak de-SSES tection isolations caused by equipment roon area high differ-WNP-2 ential temperature signal . The events occurred when there was a relatively sharp drop in outside temperature. As noted in Section 5.4.6.1.1.1 and Table 5.2-8 [ Table 5.2-9 for GG & WNP-2],
Susquehanna [ Grand Gulf /WNP-2] incorporates this type of
[HPCI]* RCIC and RHR (steam) isolation. Provide a discussion of the modifications that have been or will be made to prevent inadvertent isolations of this type which affect the availa-bility and reliability o.f the [HPCI]* RCIC and the RHR systems.
Secondly, provide the trip settings for isolation of the [HPCI]*
RHR and RCIC systems due to high area temperature in terms of degrees above ambient temperature.
Also, discuss the method of specification that would be applied.
Show that the setting could not be set too low and cause in-advertent isolation when the system is needed.
211.16 In Section 7.6.la.4.3.9.2.1 you state that the HPCI high ambient SSES (7.6.la.4) area temperature switch will start the timer and initiate (after a delay period) the HPCI isolation valve closure. Provide this time delay period and justify its selection.
211-4 211.17 You show departure from full compliance with Regulatory Gu'ide WNP-2 (5.5.2.1) 1.29 by not having ~the component cooling water portions of (App. C.2) the reactor recirculation punps seismic Category I. Your justification is that the pumps do not perform a safety function.
Justify this contention and show that a loss of component cooling water, to the recirculation pumps would not lead to unacceptable consequences.
211.18 Describe the provisions used for protection of the RCIC [HPCI GG (4.6) for SSES] and the RHR systems from cold weather [and dust storms]*
SSES -(5.4.6) in order to assure satisfactory operational performance. Al so ,
WNP-2 (5.4.7) in the assessment include the standby liquid control and the control rod drive hydraulic systems and sources of water (e.g.,
CST standby service water) for all the above systems.
- Applies to WNP-2 only.
211.19 In Section 3.5.1.2.2 you state that pressurized component (
GG (3.5.1.2) namely, pressure vessels and pressurized bottles containing noncondensible gases with an operating pressure at or above 100 psig have been evaluated as potential sources of missiles.
Provide this evaluation which should include the CR0 scram nitregen bottles and the safety / relief valve air accumulators acting as potential missiles. Describe protective barriers available to prevent missiles from' striking nearby safety systems or components.
211.20 In the consideration of pressurized compohent failures becoming WNP-2 (3.5.1.2) potential missiles, you state that thermowells and sample probes have been examined against criteria discussed in Section 3.5.1.1.2.
Provide which specific ciiterion and basis that has been applied for the thermowells and sample probes not to be credible missiles.
Secondly, justify why other pressurized components such as blank flange assemblies and pressurized vessels or bottles (e.g.,
safety / relief valve air accumulators and nitrogen accumulator tanks) have been omitted from the evaluation.
211.21 In the c'bnsideration of potential missiles, justify why other SSES (3.5.1.2) pressurized components such as blank flange assemblies and pres-surized vessels or bottles (e.g., safety / relief valve air accumula-tors and nitrogen accumulator tanks) have been omitted from the evaluation.
211.22 [Not used]
. -. L. . _ . .
. 211-5 211.23 Discuss the potential for missiles inside the containment due to GG (3.5.1.2) gravitational effects (of such components as electrical hoists SSES or any unrestrained equipment) during maintenance times, reactor WNP-2 operation, and following a LOCA.
211.24 With regard to rotating component failure missiles, show by
, GG (3.5.1.2) analysis that the impeller fragments resulting from recirculation SSES pump overspeed condition during a LOCA will not penetrate the WNP-2 pump case. Secondly, provide or reference a study that shows the probability for significant damage to occur within the con-tainment from impeller missiles being ejected out the open end of the broken pipe is acceptably low. If a similar study for another plant is to be referenced, justify its appropriateness to your plant design.
211.25 Based on the review of nuclear power plant piping system design GG (3.5.1.2) integrity, past history has shown several failures of safety SSES valve headers resulting in the valves becoming missiles (NUREG-WNP-2 0307). Since you address only the credibility of valve bonnets and stems, justify why the safety valve header and valve is not considered as a credible missile. Also, your statement that bonnet ejection is highly improbable and not considered credible missiles for valves of ANSI 900 psig rating and above is not supported. Show that should a large valve component become a missile, containment penetration would not occur. Discuss protection, such as equipment separation and redundancy, to preclude damage to the systems necessary to achieve and maintain a safe plant shutdown.
211.26 Provide a listing of the systems and equipment inside contain-SSES (3.5.1) ment necessary to achieve and maintain a safe plant shutdown.
211.27 Provide information demonstrating that loss of the operating CRD GG (4.6.1) pump at low reactor pressure (less than 500 psig) will not result l SSES in accumulator depressurization and loss of scram capability.-
! WNP-2 If the accumulator check valves leak following loss of the operating CRD pump, provide estimated time and basis before reactor scram capability becomes marginal. Also, present a testing program or procedure that would assure that operation of these check valves is acceptable over the plant lifetime.
211.28 Confirm whether the newly revised collet retainer design will SSES (4.6.1.1) be incorporated into the CRD mechanism.
! WNP-2 211,29 [We note in your response to question 110.2 regarding the concern GG (4.6.1) of cracking of the CRD return nozzles that you intend to fix this WNP-2 problem by cutting and capping the CRD return line.]* [We note in Table 1.3-8 that you intend to cut and cap the CRD return line.]**
Discuss the impact of this modification on the plant. In particular, include information covering, but not limited to, the following areas:
l
211-6 (4.6.1) - (1) Compare reactor vessel makeup capability for one and two CRD pump operation before and after the proposed modifi-cation. Commit to preoperational testing to verify the modified flow capability.
(2) Commit to preoperational testing to verify individual per-formance of modified CRD components and other aspects of the CRD system potentially affected by the cut and capped CRD return line (equalizing valves,ititers, scram times, settling function, etc.).
t (3) Should new equalizing valves be added, discuss the potential lifetime effect on drive speeds; in particular, evaluate the vulnerability of the CRD system to a voiding of the drive exhaust header after a single failure.
(4) Evaluate the lifetime effect of the added flow through such components as the drive exhaust header and stablilizing lines; in particular, discuss the increased potential of j corrosion products from carbon steel piping to deposit additional foreign matter in the drives.
(5) Discuss the potential for, and effect on, flow reversal through,the directional control solenoid valve over the 4 plant liftime.
(6) Discuss the expected effect of the CRD modifications on theA P settling function across drives to ensure latching after withdrawal.
- Add to GG only. ** Add to WNP-2 only.
211.30 Appendices G and H of the La Salle and Zimmer FSARs, respectively GG (5.4.1) provide information on the recirculation flow control system.
WNP-2 (15.0) State whether this information is applicable to Grand Gulf [WNP-2].
. If applicable, it should be referenced; otherwise, a comparable section for the Grand Gulf [WNP-2] should be provided.
Also, provide the following information:
(1) Justify the 8 degree subcooling limitation in operating the recirculation pump.
(2) Secondly, you state that if the subcooling falls below l
8 degrees Fahrenheit, the 60 Hz power supply is tripped to the 15 Hz power source to prevent cavitation of recirculation pump, jet pumps, and/or the flow control
( valve. The above conditions appear to initiate a two-
! pump trip transient. Is the pump coastdown rate result-ing from the above condition more severe than the one l
- m. . . . .
7 211-7 0
( 5.4~.1 ) used in the Chapter 15 transient analysis? If so, then (15.0) reanalyze pump trip transient with the more severe pump coastdown rate. Also, describe the consequences of a sudden increase in recirculation pump speed (possibly .
due to an increase in the frequency of the power supply).
211.31 Confirm whether Figure 5.4-5 (the reference flow control valve GG (5.4.1) characteristic) is applicable for closing and opening conditions.
211.32 Provide units definition for C in Figure 5.4-4a and b of V
WNP-2 the WNP-2 FSAR.
(5.4.1) ,
211.33 Most of the operating BWR plants have reported finding radial SSES (4.6.1) cracks on the reactor vessel feedwater nczzles and the CRD return line. To solve this problem, GE has recommended that licensees and applicants cut and cap the CRD return line.
Dis::uss the impact of this modification on the plant. In particular, "
include information covering, but not limited to, the following areas:
(1) Compare reactor vessel makeup capability for one and two CRD pump operation before and after the proposed modifi-cation. Commit to preoperational testing to verify the modified flow capability.
(2) Commit to preoperational testing to' verify individual per-formance of modified CRD components and other aspects of l the CRD system potentially affected by the cut and capped CRD return line (equalizing valves, filters, scram times, settling function, etc.).
(3) Should new equalizing valves be added, discuss the potential lifetime effect on drive speeds; in particular, evaluate l
the vulnerability of the CRD system to a voiding of the i drive exhaust header after a single failure.
(4) Evaluate the lifetime effect of the added flow through such components as the drive exhaust header and stablilizing lines; in particular, discuss the increased potential of corrosion products from carbon steel piping to deposit additional foreign matter in the drives.
! (5) Discuss the potential for, and effect on, flow reversal
! through the directional control solenoid valve over the plant liftime.
(6) Discuss the expected effect of the CRD modifications on theAP settling function across drives to ensure latching after withdrawal.
I --
211-8 211.34 Provide assurance that the essential portions of the control GG (3.5) rod drive system, namely, the 1-inch supply and return piping SSES (4.6.1) located inside the containment [for Grand Gulf (see Figures WNP-2 3.6A-15, -19, and -20)] [for WNP-2 (see Figures 3.5-20, -22, and -27)] are protected from the effects of high or moderate energy line breaks such as the high pressure core spray system, or high pressure core injection feedwater system, reactor coolant pressure boundary, etc. [In support of the above information re-quest, provide or reference equipment location or layout drawings to assure that no high or moderate energy piping systems are close to the control rod drive system or that protection is provided from the effects these pipe breaks.]* The concern is whether pipe whip and/or jet impingement can impair the capability to scram. In addition to the above requested evaluation, assess damage to the cluster of CRD return and supply lines, and scram capability by postulating rupture of a single CRD supply or return line.
- Add to SSES only.
211.35 Per Table 1.3-8, the Grand Gulf Nuclear Station will incorporate GG (4.6.1.1) the " fast scram" control rod drive (FSCRD) system as it was proposed on the GESSAR docket. Provide any new available information on the FSCRD qualification test programs. Specifi-cally, the status of field evaluation--where this unit has been installed and monitored in Peach Botton Unit 3, manufacturing qualifications, and production tests. Discuss how these latest results compare to those obtained from previous acceptance testing.
211.36 Note 4 in Figure 4.6-10 states that the charging header shall GG (4.6.1.1) not exceed 1510 psig and any pressure in excess of this value will damage the CRD during a scram. However, in Section 4.6.1.1.2.4.1 you stat.e that an accumulator hydraulic charging pressure of approximately 1750 to 2000 psig is required. Since the charging header is connected to the hydraulic control units, clarify whether there is a piping design pressure change within and down-stream of these units. If so, provide the interface location between the high and low pressure boundaries. If not, correct or discuss the discrepancy between the above two pressure values and how it affects the CRD design.
211.37 Per the Standard Review Plan 4.6 and Regulatory Guide 1.70, GG (4.6.1) Rev. 2, information for combined performance and evaluation of reactivity systems is required. In particular, address the vulnerability of the reactivity control systems (control rod drive and the standby liquid control systems) to cocinon mode failures.
~
211-9 211.38 The RHR system shall be capable of bringing the reactor to a GG (5.4.7) cold shutdown using only safety-grade systems. Confirm that SSES this requirement is met. Include in your assessment the air WNP-2 supply system used to operate the RCIC (or HPCI) steam and condensate control valves located at the RHR heat exchanger when the RHR system is in the steam condensing mode.
211.39 The RHR system shall be capable of bringing the reactor to a GG (5.4.7) cold shutdown with only onsite or offsite power available and SSES with the most limiting single failure. [ Figures 15.2-10 and WNP-2 -11 show available success paths to achieve a cold shutdown condition; however, vessel depressurization via the RHR system in the steam condensing mode is not shown. For com-pleteness, provide a corrected figure or justify this omission.
If vessel depressurization were to be achieved via manual relief valve actuation, how many valves would be required?]*
Describe your plans for testing the alternate shutdown cooling modes of operation. Demonstrate that adequate passage of water through the safety / relief valves can be achieved and maintained when the alternate method is in use. Include the quantity of air supplied, the source, and the time before the air is exhausted.
- Add to SSES and WNP-2.only.
211.40 During the shutdown cooling mode, the " flush water" valves GG (5.4.7.2) are opened and closed outside the control room. Specifically SSES identify the operated local flush water valves and the source WNP-2 of flush water. Discuss the consequences assuming the operator would omit this procedure and/or forget to close a local flush water valve and continue shutdown operations.
[ Include available interlocks in the discussion.]*
- Add to SSES and WNP-2.
211.41 In Section 5.4.7.1.3 you identify the RHR relief valves and the GG (5.4.7.1) RHR design pressure used as the sizing basis. Expand ycur SSES discussion by providing the [ relief valve capacity, nominal WNP-2 set points]*, set point tolerance, and ASME class rating of the valves and lines.
In addition, discuss the vulnerability of the RHR system to malfunctions which could result in overpressurization of low pressure piping. Support your evaluation by providing an outline of all operating procedures required to bring the plant to a cold shutdown condition from hot standby and procedures for plant startup from cold shutdown.
- Delete this for SSES.
-~
. . 211-10 211.42 Provide your safety design basis and need for incorporating a WNP-2 (5.4.7.1) pressure interlock to prevent the connection of the RHR discharge piping to the primary system whenever the pressure difference across the discharge valve is greater than the design differential.
Also, identify the affected valves.
211.43 In section 5.4.7.2.1, you state that RHR pump start is prevented GG (5.4.7.2) when the suction valve (s) are not open. Confim that RHR pump trip would also occur assuming the pump is operating and one or both suction valves inadvertently close. Show that the above pump trip feature does not compromise the ECCS function.
211.44 Provide more detailed infomation regarding the actuation of GG (5.4.7.1) the automatic minimum flow valves used for RHR pump protection SSES against damage from a closed discharge valve. For example, WNP-2 specify flow rate quantities that signal minimum flow valve opening and closure on low main line flow and high main RHR line flow, respectively. Also, state whether the control system meets IEEE-279 standards. [ Confirm that the minimum flow line valve restrictors are designed to safety-grade standards (e.g., seismic Category I, ASME Code Section III).]*
[Also, provide the design pressure of the minimum flow line.]**
211.45 Figure 5.4-15 describes the RHR pump characteristic curves. Two WNP-2 (5.4.7) sets of curves are shown--one for full diameter piping and the other for minimum diameter piping. Specify which curve (head vs flow rate) was used in the ECCS and RHR perfomance evaluation.
211.46 Per Table 5.4-3, the RHR isolation valves F008 and F009 are GG (5.4.7) signaled to close on reactor low water level. Clarify whether SSES this valve isolation signal is based on the same signal as the WNP-2 RHR pump actuation in the LPCI mode, which is a water level of 1.0 foot above the active core. If not, provide vessel water level that isolates the RHR suction valves and show that core cooling can be maintained assuming a pipe break outside the containment. Hence, provide the following additional infomation assuming a pipe break outside containment in the RHR system when the plant is in a shutdown cooling mode:
(1) Identification of systems available for maintaining core cooling.
(2) Maximum discharge rate resulting from the break and the time frame available for recovery based on the discharge rate and its effect on core cooling.
211-11 (5.4.7) (3) Identify the alarms available to alert the operator to the event, assurance that recovery procedures are available, and show that adequate time is available for operator action.
(4) Following the moderate energy line break, single failure criterion should be applied consistent with SRP 3.6.1 and BTP APCSB 3-1.
211.47 Discuss system design provisions to prevent damage to the RHR GG (5.4.7) (LPCI) pumps against pump runout conditions during ECCS and test SSES modes of operation. [Also, note that Figures 5.4-13a, b and WNP-2 5.4-14a of the FSAR show no restricting orifices in the discharge lines. (A metering orifice is shown.) The discharge lines should incorporate a restricting orifice unless the metering orifice can perform the same function.]*
- Add to WNP-2 only.
211.48 Figure 5.4-13 of the FSAR shows the labeling of the orifices SSES (5.4.7) in the discharge lines as "F0". Clarify whether this is a restricting orifice, normally labeled as "R0".
211.49 Explain the apparent discrepancy between Figure 5.4-14a and SSES (5.4.7) Table 1.3-3 which identifies three RHR pumps and four RHR pumps, respectively.
211.50 Provide a more detailed description and location of the RHR GG (5.4.7) pump suction strainer inside the suppression pool. Include SSES pipe bends and the minimum height of the suppression pool WNP-2 water level above the suction strainer. Show that the NPSH at the center line of the RHR pump will be met at the pump's design condition as well as at the most limiting operating condition.
Also, discuss the size of particles that could pass through the strainer and continue to the RHR pump passages. How much material blockage would it take to significantly affect RHR pump suction flow from the suppression pool following a LOCA?
211.51 Providetheprocessdata(flow, temperature,ar, pressure WNP-2 (5.4.7) information) for all RHR system modes of operat .on.
Specifically, per Figure 5.4-14a, ynu eference MPL Item No. E12-1020.
211.52 Provide pressure interlock set points used in the prevention GG (5.4.7.1) of opening the RHR isolation valves F008 and F009 to the low SSES pressure suction piping, and for the initiation of valve closure WNP-2 on increasing reactor pressure.
211-12 211.53 Confirm that all valves performing an isclation function between GG (5.4.7) the high pressure and low pressure boundary in the RHR system SSES (e.g., check valves and motor-operated valves) meet the leak WNP-2 testing and inspection requirements of the ASME Section XI code for Category A valves. A combination of two or more check or motor-operated valves in series should have design provision for individual leak testing of any two valves.
211.54 [ Note 12 in Figure'5.14-13a states that "between valves M0 F008 GG (5.4.7) and M0 F009 consideration should be given to thermal expansion SSES of contained water."]* Comit to providing a means for pressure WNP-2 relief between the two RHR isolation valves [F008 and F009]** or show by analysis that piping integrity would be maintained assuming a LOCA or steam line break would cccur and the trapped water between the valves would thermally expand.
- Add to WNP-2. ** Delete for WNP 2 only -
211.55 Provide test acceptance criteria in Section 14.2.12.1.7 WNP-2 (5.4.7) regarding preoperational testing of the RHR system.
(14.2.12.1) 211.56 Operation of the RHR system in the steam condensing mode GG (5.4.7) involves partial draining of one or both RHR heat exchangers SSES and introduction of reactor steam into initially cold lines WNP-2 and heat exchangers. Descritie the methods (e.g., valve operation, air introduction, etc.) and provisions to be used to prevent occurrence of water hamer during the initiation of operation in this mode, and the change to the pool cooling mode. When the RHR is used in the steam condensing mode with one or both heat exchangers, can the jockey pump system fill the lines to the injection valve in the core spray and RHR lines? If not, what procedures would be used to prevent water hamer following startup of the core spray or RHR pumps?
Pressure relief valves and lines designed to prevent overpres-surization of the RHR system are routed outside containment
, before being returned to the suppression pool. Discuss design
! provisions made to mitigate possible water hammer in these lines.
Secondly, confirm that these relief lines are capable of taking the seismic and dynamic blowdown loads without loss of piping integrity.
211.57 Discuss the procedures for minimizing the potential for exceed-GG (5.4.7) ing the allowable cooldown rate (greater than 100 degrees SSES Fahrenheit / hour) of the RHR and the reactor coolant system when WNP-2 placing the plant in a shutdown cooling mode following planned normal conditions or an emergency.
i i
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- s 211-13 211.58 Discuss the RHR pump reliability for long-term operation. 'Long-GG (5.4.7) tem reliability should be demonstrated by either operational SSES experience or testing. If previous operational experience should WNP-2 be cited as the basis for qualifying the pumps, state any pump design differences and conditions of previous pump operations.
211.59 Leakage of steam from the HPCI steam line past the normally closed
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SSES (5.4.7) valves F051 and F052 can and has caused steam bubble fomation in the RHR heat exchangers with resultant water hammer following startup of the RHR pumps. Describe the provisions (e.g., sensors with alams) and procedures you plan to use in preventing such an occurrence due either to leakage or inadvertent valve opening.
211.60 Confirm that the RCIC electro-hydraulic system integrated with GG (5.4.6) the turbine governing valve is of a safety-grade design (e.g.,
seismic Category I).
211.61 Provide an RCIC pump performance curve that depicts flow rate GG (5.4.6) versus reactor vessel pressure. Also, identify the most limiting.
SSES operating condition and specify the NPSH margin under this WNP-2 condition.
211.62 It appears that it is possible for some steam condensate to GG (5.4.6) remain in the lines leading to the RCIC steam turbine. (This
. SSES occurs when the steam isolation valves would be temporarily closed WNP-2 for maintenance.) Discuss whether the amount of liquid can cause damar,e to the RCIC turbine so that the system is incapable of delivering water to the reactor vessel as required. Also, describe the design modifications you propose to prevent water hammer effects at the turbine exhaust.
211.63 An isolation signal closes a number of valves in the RCIC system.
GG (5.4.6.1) In particular, the affected valves are F063 and F064 (F0083*,
SSES [F007 and F008]** located inside and outside containment, branched WNP-2 off the main steam line. However, the P&ID shows that these valves are keylocked open. Justify this apparent discrepancy and evaluate the consequences of a postulated pipe break downstream of the first or second isolation valve for steam flow rates less than or greater than the 300 percent of the steady-state steam flow indicated in this section.
- Applies to WNP-2. ** Apply to SSES only.
211.64 The acceptance criteria of SRP 5.4.6 (page 5.4.6-3) state that, WNP-2 (5.4.6) "As a system which must respond to certain abnomal events, the RCIC system must be designed to seismic Category I standards, as defined in Regulatory Guide 1.29." The condensate storage tank which is the normal suction supply for the RCIC is not seismic Category I. The suppression pool provides a seismic Category I backup source of water, but the switchover requires operator action.
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211-14 (5.4.6) You should confirm that WNP-2 will conform to the above acceptance criteria. Any one of the following alternatives would be an accept-able approach for meeting the acceptance criteria: (1) seismic Category I supply, or (2) safety-grade switchover to a seismic Category I supply, or (3) manual switchover to a seismic Category I supply if appropriately justified. Discuss the approach to be used for WNP-2.
211.65 For the failure of the normal RHR shutdown cooling event analysis, SSES (15.2.9) provide the reactor vessel temperature and pressure time traces WNP-2 and the. suppression pool temperature time trace for the alternate shutdown cooling modes--activity C1 and C2 as described in Figure 15.2-11. Include the assumed initial pool and service water temperatures.
211.66 Provide estimated times to achieve a cold shutdown condition SSES (15.2.9) for the alternate cooling paths Activity C1 and C2 as described WNP-2 in Figure 15.2-11.
211.67 The FSAR states that the accumulator sizing for the power-GG (5.2.2) operated relief valves is sufficient for one actuation; and SSES (5.4.7) for the automatic depressurization system (ADS) valves it is WNP-2 (6.3) sufficient for two actuations. A "noninterruptible" safety-grade source of air for the ADS valves is required to terminate certain postulated transient and accident events without loss of the ADS function. Show that an adequate supply of air will exist to operate the ADS valves for the following conditions:
(1) the alternate method of achieving and maintaining a cold shutdown following a loss of offsite power with a worst single failure in the RHR system; (2) for a small LOCA with failure of high pressure ECCS where the ADS valves would be used for reactor vessel depres-surization and maintaining long-term cooling. Include a discussion on procedures to be used to replenish coolant inventory; and (3) for a small steam line break disabling the RCIC concurrent with a single failure of the HPCS [HPCI] that would require ADS function to depressurize the reactor vessel. Consider the air supply needs for long-term cooling (e.g., how would reactor vessel inventory be maintained when decay heat repressurizes the vessel above the shutoff head of the low pressure cooling system?).