ML20058L052
| ML20058L052 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 07/19/1990 |
| From: | Dick G Office of Nuclear Reactor Regulation |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| TAC-73009, TAC-73010, NUDOCS 9008060098 | |
| Download: ML20058L052 (73) | |
Text
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July 19, 1990-Docket Nos. 50 498 l 4 and 50-499 LICENSEE: Houston Lighting & Power Company (HL&P)
FACILITY: South Texas Project, Units 1 and 2
SUBJECT:
MEETING TO DISCUSS STAFF REVIEW 0F SOUTH. TEXAS PROBABILITY i AND SAFETY ASSESSMENT (PSA) (TAC NOS 73009 AND 73010)
The subject meeting was held on November 28 and 29, 1989. The list of attendees is shown in Enclosure 1. Review of the PSA was underway by the staff anditscontractor,SandiaNationalLaboratories(Sandia). Prior to the meeting, Sandia, through the staff, provided the licensee with a list of questions. The licensee prepared written responses which were distributed and discussed at-the meeting. Enclosure 2 documents the questions and answers.
-The meeting included a plant tour of Unit 2.
OriginalSigned By:
George F. Dick, Jr., Project Manager Project Directorate IV-2 Division of Reactor Projects . III, IV, Y and Special Projects Office of Nuclear Reactor Regulation
Enclosures:
As stated cc w/ enclosures:
See next page
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OFFICIAL RECORD COPY Document Name: STP MTG
SUMMARY
/73009/10
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2 cc w/ enclosures:
Senior Resident Inspector Jack R. Newman, Esq.
U.S. Nuclear Regulatory Comission Newman & Holtzinger, P.C.
P. O. Box 910 1615 L Street, N.W.
Bay Citv, Texas 77414 Washington, D.C.- 20036 Mr. J. C. Lanier Licensing Representative-Director of Generation Houston Lighting and Power Company Lity of Austin Electric Utility Suite 610 i
.721 Barton Springs Road Three Metro Center-
' Austin, Texas 78704 Bethesda, Maryland 20814
'Mr. R. J. Costello Bureau of Radiation Control -l Mr. M. T. Hardt State of Texas City Public Service Board l 1101 West 49th Street P. O. Box 1771 Austin, Texas -78756 l San Antonio, Texas 78296 Rufus S. Scott I Mr. R. P. Verret Associate General Counsel Mr. D. E. Ward Houston Lighting & Power Company Central Fower and Light Company P. O. Box 61807 i P. O. Box 2121 Houston, Texas 77208 >
Corpus Christi, Texas 78403 Mr. Donald P. Hall INPO . Group Vice-President, Nuclear Records Center Houston Lighting & Power Company L 1100 Circle 75 Parkway P. O. Box 1700 L Atlanta, Georgia ~ 30339-3064 Houston, Texas 77251 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 1000 Arlington, Texas 76011 Mr. Joseph M. Hendrie 50 Be11 port Lane Be11 port, New York 11713 l Judge, Matagorda County l Matagorda County Courthouse 1700 Seventh Street-Bay City, Texas '77414 L Mr. M. A. McBurnett Manager, Operations Support Licensing Houston Lighting & Power Company P. O. Box 289 Wadsworth, Texas 77483 L
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.. .r I ;g . * 's Enclosure 1 ATTENDANCE LIST.
MEETING ON SOUTH TEXAS PSA November 28 and 29,1989 '
Name Organization G. Dick NRC E. Chelliah- NRC G. Kelly NRC W. Harrison HL&P S. Rodgers HL&P ,
-B. Stillwell HL&P R. Mur y HL&P M. Powell HL&P R. Boyer HL&P T. Wheeler Sandia J. Lambright Sandia A. Camp Sandia T. Sype Sandia E. Klamerus Sandia J. Darby SEA, Inc.
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November 28-29, 1989-South Texas PSA Questions and Answers ,
Question it:
How was - DC control power for circuit breaker trip coils considered?- ,
- Response:
The plant model uses " Support State Methodology" to ensure accurate . trecking of of the varied interf aces between front line and support systems. In the case of de control power, the following explanation is provided.
Each train in a system is completely separate from the other trains.
Each major support system is included in one of the two support system event trees; the electric power tree or the mechanical auxiliary tree. DC power is included in the electric power tree (top events DA, DB , and DC for the three major trains, DC train D is included with the turbine driven ATW pump).-
If a DC power train fails, the associated plant train is L- modeled as being failed.
l The interface between DC power and the supported system is .
l at the AC switchgear (large motors) or at the feed to a cabinet (DC solenoid valves).
Control- power failure at a component is assumed to be j included with the device (e.g. breaker control power fuse failure is counted with the breaker).
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Question 2:
The support to frontline system dependency matrix (Table 5.3-2) indicates that EAB HVAC is required for both High and Low pressure Injection pumps. However, the FSAR Section 9.4.2.2 states that the ECCS pump rooms are cooled by the FHB HVAC or by supplementary coolers. The PSA system description for S7 ,
assumption J.2. (Book 10) states with respect to ECCS pump room !
cooling " ...it is assumed that room cooling is not necessary due I to natural convection that will be available." What justification exists for this assumption? Why does Table 5.3-2 indicate that the High and Low Pressure Injection pumps depend on EAB HVAC? (If the intent of Table 5.3-2 is to show that the electrical supply for the ECCS pumps depends on EAB HVAC, this is not necessary because that dependence is already indicated in !
Table 5.3-1.) l Response: ,
- a. The PRA assumed that room cooling is not necessary due to natural convection that will be available. This was an assumption based on a walkdown of the ECCS pump '
rooms and the surrounding area of the Fuel Handling Building (FHB). Earlier this year a decision was made to investigate this assumption. A study was performed to deta rmine a time-temperature profile for an ECCS room in post-accident conditions without the' room coolers functioning. The study assumed that FHB HVAC was successful, but did not take credit for natural convection. The ability of the ECCS equipment to function in this environment is currently being evaluated. The pumps and valves have been shown capable of operating for seven days at an enveloping temperature. The effort to demonstrate the adequacy l
of cabling for the pumps and valves is not yet complete.
- b. The support to frontline table entry is made to ensure consistent treatment of the EAB HVAC failure and it's l effect on the electrical distribution system. Failure of this HVAC system does not immediately fall any equipment. For this reason, there is a table note (Note S in Table 5.3-1, Note T in Table 5.3-2) to indicate the assumed failure. The entry is primarily a " consistency" entry to reduce coding errors.
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Question 3: l Loss of Instrument Air has been included as an initiator, I but appears not to have been included in the system dependency 1 matrix. How was loss of instrument air considered in its effect on mitigating systems operations? l Response: l Instrument Air does not support the operation of systems a required to mitigate the consequences of a plant transient and is therefore not required or modeled in the support systems model.
It is included in the Charging system for RCP seal cooling after loss af offsite power, Instrument Air is provided to several systems modeled in the PSA, for example:
o Auxiliary feedwater cross-connect valves (closes normally, fail-closed, not modeled in PSA).
o RHR heat exchanger outlet and bypass valves are used for temperature control during plant cooldown, the outlet valve is normally open and fails open, the bypass valve is normally closed and f ails closed. These valves must remain
-in their normal (failed) position in the PSA.
Other systems have instrument air for similar nonsafety functions..
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.. '.o Question'4:
Section B.i HEOB02 estimates that over one hour is required for steam generator dryout following ree: tor and turbine trip with no feedwater. This section assumes the reactor trips on low-low steam generator level "... estimated to be about 90% of the normal full-power liquid inventory." The FSAR figures 15.2.9A and 15.2-10 indicate that the sacondary mass in each
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steam generator is about 60,000 lbm at low-low level trip which.
is less than 50% of the full power inventory. Using this lower.
inventory, dryout is estimated to occur at about 30 minutes.
What is the justification for the 90% assumption? How does a decrease in time to dryout from one hour to 30 minutes affect the PSA model? Is the discrepancy due to the fact that level is calculated by measuring the pressure drop across two taps in the downcomer and flow losses are much less without feedwater?
Response
The comment that low-low level corresponds to approximately 60,000 lbm is correct. However, additional time is required to evaluate the impact on the PSA.
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Question 5:
Verify that the availability of the pressurizer PORV's in
-combination with the time to boil the steam generators dry allow-HHSI to provide makeup for feed and bleed without requiring use of CVCS early on until the primary can be depressurized to below the HHSI shutoff head. Are both PORV's required.
Response
The CVC system is not required for feed and bleed. Feed and bleed of the RCS is only required if secondary cooling is lost (i.e. no main or auxiliary feedwater). At low steam generator water levels (37% wide range) with no feed flow, feed and bleed is started. One HHSI pump and the pressurizer PORV's are required for feed and bleed. (See POP 05-EO-FRH1 Step 8).
Both PORV's are required for feed and bleed. >
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Question 6:
Does plant data validate the assunption that i normal feedwater is always isolated due to low T(p. gy 5. 4-10) ing a follow reactor trip? '
Response
Plant trip data. to date does not support this assumption.
This is primarily due to improved feedwater bypass level control at STPEGS which allows finer control of flow at shutdown. At the time of the design freeze on the PSA (October 1988) , there was not enough plant trip data to indicate that this assumption was overly conservative. During the model update (currently planned for 1990) this assumption will be reviewed to incorporate our current plant experience.
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..- *o Question 71 Given that one ECCS train feeds the break, is one ECCS_ train
- consisting of a high and low pressure pump injecting into one primary cold leg sufficient for all size LOCA's? How many accumulators must inject for the various size LOCA's?
Response
One ECCS sufficient trt.n injecting to mit yate into an intact RCS loop is all LOCA's.
the PSA assumes two trains must be available to overcome theFor medium and-large problems associated with modeling the location of a particular break.
Requiring two trains ensures that at least one train will be injecting into an intact RCS loop. For small LOCA's, Westinghouse analysis indicates one ECCS train injecting into its RCS loop (with conse quences or without a break) is sufficient to mitigate the
. This is consistent with chapter 6.3 of the FSAR.
The accumulators are not included-in the pSA. If the r
accu'mulators work, but ECCS fails, core damage results, if the L accumulators fail but ECCS works, it was assumed that no core damage occurs (minor clad perforation may occur and PCT may be exceeded for some fuel rods). This assumption is based upon FSAR analysis for other Westinghouse plants that do not have '
This system may be added to the model for the Level II IPE analysis primarily because of it's accident management capabilities.
-Question 8:
What is the impact of- spurious closure of the seal return valve? Verify that this does not de-stage the seal (s) leading _to seal fajiure.
Response
FSAR section 5. 4.1. 3.1 discusses seals response to spurious return line isolation. No seal 14CA will occur as the second stage seal will take over the function of the first stage seal.
See the attached RCP seal descriptions for further discussion.
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STP FSAR l The reactor coolant pump assembly is equipped with an oil collection system that is designed(SSE). to maintain structural integrity durir.g and after $sfe Shut. l3
-down Earthquake The collection system is capable of collecting oil l3 from all potential leakage sites in the RCP notor lube oil subsystem. In particular, pans, drainthe puntp lines, motor and is installed a collection with enclosures, splash guards, drip tank. I3 33 l}280.
To protect against an oil leak in the 011 Lift System, an enclosure is pro. 17N vided isolating the high pressure oil components from the environment. The upper oil cooler flanges are fitted with splash guards, directing any oil leakage downward to a drip pan. Drip pans are provided under the upper oil 3 pot box. level detector, upper oil por fill and drain valve, and upper RTD conduit !
A catch basin is provided around the motor shaft, extending out from the ,
i motor to include the area below the lower oil pot.
Drain lines large enough to accommodate the largest potential oil leak are l3 provided from the drip pan to a collection tank sized to hold the lube oil inventory of at least one RCP motor.
5.4.1.3 Design Evalustion.
5.4.1.3.1 Punp Performance:
which equal or exceed the required flow rates.The RCPs are sized to deliver flow at rates (RCS) tests confirm the total delivery capability. InitialThus, Reactor Coolant assurance of System ade - ,
quate forced circulation coolant flow is provided prior to initial plant oper-ation.
The estimated performance characteristic is shown on Figure 5.4 2.
The Reactor Trip System (RTS) ensures that pump operation is within the as-sumptions used for loss of coolant flow analyses, which also assures that ade-l quate- core cooling is provided to pemit an orderly reduction in power if flow from a RCP is lost during operation.
An extensive test prog am has been conducted for several years to develop the controlled tions. leakage shaft seal design for pressurized water reactor applica- 3E Long term tests were conducted on full size prototype seals. Oper-ating plants continue to demonstrate the satisfactory performance of the con-l trolled leakage shaft seal pump design.
The support of the stationary member of the number 1 seal (" seal ring *) is such as to allow large deflections, both axial and tilting..while still main-taining its controlled gap relative to the seal runner. Even if all the gra-phite were removed from the pump bearing, the shaft could not deflect far enough to cause opening of the controlled leakage gap. The ' spring rate
- of.
the hydraulic forces associated with the maintenance of the gap is high enough to ensure that the ring follows the runner under very rapid shaft deflections.
Testing of pumps with the number 1 seal entirely bypassed (full system pres- l 3B sure on the number 2 seal) shows that relatively small leakage rates would be maintained for long periods of time (with the pump not rotating); even if the number 1 seal fails entirely during normal operation, the number 2 seal would maintain ator.
these small leakage rates if proper actions are taken by the oper-The plant operator is warned of number 1 seal damage by increase in the 5.4 3 Amendment 55
STP FSAR number 1 seal leakoff. Following varning of excessive seal leakage condi-tions, the plant operator should close the number 1 seal leakoff line and se.
cure the pump, as specified in the instruction manual. Cross leakage from the l pump does not occur if the proper operator actions are taken subsequent to warning of excessive seal leakage conditions.
The effect of loss of of f site power (LOOP) on the pump itself is to cause a temporary stoppage in the supply of injection flow to the pump seals and also of the cooling water for seal and bearing cooling. The emergency diesel generators (DGs) are started automatically upon LOOP enabling coeponent cooling and seal injection flow to be automatically restored. 3g 5.4.1.3.2 Coastdevn capability: It is important to reactor protection 1
that the trip. reactor coolant continues to flow for a short time after reactor In order to provide this flow in a LOOP condition, each RCP is provided 138 with a flywheel.
Thus, the rotating inertia of the pump, motor and flywheel is employed during the coastdown period to continue the reactor coolant flow.
The coast-down flov transients are provided on the figures in Section 15.3.
The pump / motor system is designed for the SSE at the site. Hence, it is concluded that the coastdown capability of the pumps is maintained even under the most adverse case of a LOOP coincident with the SSE. Core flow transients cre discussed and figures are provided in Sections 15.3.1 and 15.3.1.
l33 5.4.1.3.3 Bearing Interrity: The design requirements for the RCP bear-ings are primarily aimed at ensuring a long life with negligible wear, so as to give accurate alignment and smooth operation over long periods of time.
The surf ace-bearing stresses . ire held at a very low value, and even under the cost severe seismic transients do not begin to approach loads which cannot be adequately carried for short periods of time.
t Because there are no established criteria for short time stress-related fail-l ures in such bearings, it is not possible to make a meaningful quantification of such parameters as margins to failure, safety factors, etc. A qualitative analysis of the bearing design, embodying such considerations, gives assur-ance of the adequacy of the bearing to operate without failure.
l Lov oil levels in the lube oil sumps signal alarms in the control room and re-quire shutting down of the pump. Each motor bearing contains embedded temper-oture detectors, and so initiation of failure, separate from loss of oil, is indicated and alarmed in the control room as a high bearing temperature. This again, requires pump shutdown. If these indications are ignored, and the bearing proceeds to failure, the lov melting point of Babbitt metal on the pad l38 surfaces ensures that sudden seizure of the shaft vill not occur. In this ovent the motor continues to operate, as it has aufficient reserve capacity to drive the pump under such conditions. However, the high torque required to l
drive the pump will require high current which vill lead to the motor being shutdown by the electrical protection systems.
5.4.1.3.4 Locked Rotor: It may be hypothestred that the pump impeller might severely rub on a stationary member snd then seite. Analysis has shown that under such conditions, assuming instantaneous sefrurt of the impeller, the pump-shaft f alls in torsion just below the coupling to the motor, disen-gaging the flywheel and motor from the shaft. This constitutes a loss of 5.4-4 Amendment 38 1
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PAGE 10F 21 NAGER AND TEOD?ICAL STAFF TRAINING PROGPAM PIANT SYSTEMS i
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, PAGE 2.0 INTRODUC' TION 4
I 2.0 HYDRAULIC SECTION DESCRIPTION 5 CASING 5
IMPELLER /DITTUSER 5
SUCTION ADAPTER 6
THERHAL SARRIER/ HEAT EXCHANGER 6 PUMP BEARING 6,
3.0 SHM'T SEAL ASSEHBLY DESCRIPTION 6 NUMBER ONE SEAL 9
NUMBER TWO SEAL IO NUMBER THREE SEAL la 4.0 HOTOR S?.CTION DESCRIPTION 12 ROTOR 12 UPPER BEARING 13 LOWER GUIDE BEARING 14 FLYh* HEEL 14 ANTI-REVERSE ROTATION DEVICE 15 STATOR 15 l
67217/408/003 A
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l TABLE OF CORTERTS I (Continued) e PAGE i 5.0 RCP INTERFACE SYSTEMb 16 l CCW 16 i SEAL INJECTION / LEAKOFF 17 6.0 RCP OPERATIONAL LIMITS 19 STARTING PREREQ'JISITES 19 RCP HDTOR STARTING LIMITS 19 ,
RCP TR".P CONDITIONS - NORMAL OPERATIONS 20-RCP TRIO CONDITIONS - ACCIDENT CONDITIONS 20 7.0 RETERENCES 21 r
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, NTS/PIANT SYSTEMS - RCPs PAGE 4 OF 21 30 INTRODUCTION The function of the reactor coolant pump is to circulate coolant (water) through the reactor core and steam generators. This flow must be sufficient to remove heat from the core. The reactor
! coolant pump is a vertical, motor driven, single-stage, centrifugal ,
controlled-leakage pump designed to move large volumes of reactor coolant at high temperatures and pressures.
l The RCP consists of three (3) major assembliest the hydraulic l
section, shaft seal section and motor section (Figure 2)
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The hydraulic section consists of a casing, an impeller, diffuser, thermal barrier / heat exchanger, and pump radial bearing. The shaft seal section consists of three devices; the i' No. I controlled-leakage, film-riding face seal and the Nos. 2
, and 3 rubbing face seals. These seals are contained within the
! rnain flange and seal housing. The motor section consists of a vertical solid shaft, squirrel cage induction motor, an oil- <
lubricated double Kingsbury thrust bearing, two oil-lubricated radial bearints, and a flywheel with an anti-reverse rotation device. ,
i The reactor coolant pumps are located inside the primary loop compartment within the containment. Pump A is located in the northwest section, pump B in the northeast section, pump C in the southeast section and pump D in the southwest section. The following elevations are typical of all four pumps: lower ,
foundation - EL. 19'0', discharge pipe - EL. 32. 3, motor - EL.
46'6*.
The pumps are powered from 13.8 KV, 36, 60 Hz, 1200A Auxiliary Buses: RCP 1A - AUX BUS 1F, RCP IB - AUX BUS 1G, RCP 1C - AUX i BUS 1H, RCP ID - AUX BUS IJ.
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2.0 HYDPAULIC SEC' TION DESCRIPTION i
The pump is vertically mounted and is arranged with a bottom suction and a radial side discharge nosale. Reactor coolant is '
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drawn into the casing, through the impeller, discharges through t i passages in the diffuser, and out through the discharge nortle ir}
the side of the casing.
CASING (Figure 3) '
The pump casing has a concentric configuration which minimizes the intensity of the casing wall stresses that are associated with the high system pressures and the large size !
of these casings. The casing is a spherical 304 (SA351-CF8)
SST casting. The casing has three supports at the upper flange elevation for mountir.g to the pump support system. A turning flange functions ea an integral part of the casing by directing coolant flow toward the pump discharge path.
i' IMPELLER /DIITUSER (Figure 3) i The impeller is a 304 SST (CF8) casting with an outside diameter of approximately 40 inches. It is attached to the lower end of the shaft by a tapered shrink fit, a key as a backup, and an impeller nut threaded and locked to the i shaft. The diffuser is also a 304 SST casting and is welded to the turning flange. It is located directly above the impeller from which it accepts flow.
The mixed flow impeller has seven integral vanes. The '
primary function of the impeller is to impart energy to the pumped fluid. This energy is added to the fluid within the impeller in the form of increased static head and kinetic energy (velocity head). The fluid is then delivered to the inlet of the diffuser.
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Further energy conversion occurs within the diffuser. Here the excess kinetic energy (velocity head) of the fluid is converted to an additional static head (pressure head) rise by gradually reducing the fluid velocity in the expanding flow channels between twelve diffuser vanes. A flow i splitter which optimises flow distribution is welded to the top of the vanes. The axial flow configuration of the diffuser produces a design of minimum over-all diameter which permits withdrawal of the diffuser through the casing flange as a part of the pump assembly.
Most of the energy conversion processes have been completed by the time the fluid enters the pump casing plenum from the diffuser exit. The primary function of the casing is to direct the fluid from the diffuser outlets to the radial discharge outlet. '
SUCTION ADAPTER (Figure 3)
The suction adapter guides the flow from the casing suction to the impeller. It is bolted into the bottom inside surface of the casing and extends upward to the impeller where it forms a labyrinth seal with the lower shroud j surface of the impeller. It is a 304 SST (CF6) casting.
The function of the suction adapter is to direct flow from the suction norrie pipe to the impeller while minimizing recirculation flow from the impeller exit to the impeller entrance.
TIIERMAL BARRIER / HEAT EXCHANGER (Figure 4 )
I The thermal barrier surrounds the heat exchanger and is
- l. located adj acent and interior to the diffuser and turning flange.
l The function of the barrier is to minimte heat transfer from the reactor coolant to the bearing and heat exchanger. The barrier consists of twenty-one evenly spaced, thin, concentric steel cans, closed by a seal weld at the top and open at the bottom.
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.e The heat exchanger is located interior to the thermal barrier just below the pump bearing. The function of the ;
heat exchanger is to act as a backup to tne normal seal inj ection water to maintain the bearing and shaft seal i system at a desirable low temperature. The heat exchanger I
also serves to limit heat flow to the pump internals. The assembly consists of eight coil assemblies, continuous spiral wound, and two coils high. The coils are ma6e from three-quarter inch 0.D. 316 ssT tubing. The tube side is supplied with low pressure cooling water 105 F maximum at 40 ppm from the component cooling Water system.
During normal operation, the heat exchanger is passive in providing cooling for the pump bearing and shaft seal assembly; the bulk of the cooling requirements are supplied by the injection water. During normal injection, 6 gpm of high pressure water is introduced near the top of the pump.
( Approximately 3 gpm of this flow upward as seal leakage to cool the shaft seal assembly. Host of the remaining 5 gpm i flow downward and around the pump bearing to maintain required bearing temperatures. A small portion flows downward around the shaft and through the four sets of thermal barrier labyrinths located adj acent to the shaft.
The heat exchanger comes into full operation during a loss of seal injection water.
For this condition there is upward flow of hot primary water through the pump equal to seal leakage of approximately 3 gpm. A small portion of this flow short circuits the heat exchanger and- flows upward around the shaft and through the thermal barrier labyrinths. However, most of the water flows across the heat exchanger cooling coils and is cooled sufficiently to serve as a coelant for the pump bearing and shaft seal assembly.
67217/408/003 I
- =., ' .,NTS/PIANT SYSTD4S - RCPs PAGE 8 OF 21 )
I PUMP BEARING (Tigrure 4)
The pump bearirig is a sleeve / journal, hydrodynamic, self aligning radial bearing. It is located above the heat exchanger and just below the shaft seal assembly. The radial bearing consists essentially of a two-piece horizontally split housing, a bearing cartridge and a journal all made of 304 SST forgings. The I.D. of the housing is machined to a spherical diameter that mates with a satellite-overlaid spherical surface (cobalt based) on the bearing cartridge. Carbon-graphite rings are shrunk in the bearing cartridge and form the bearing surface. The bearing utilizes cooled primary water (seal injection) as a >
lubricant.
3.0 SHAPT STJsL ASSEMBLY DESCRIPTION -
The shaft seal assembly is located concentric to and near the top end of the pump shaf t. The seals are contained in a primary pressure boundary seal housing which is bolted to the top side of the thermal barrier flange. The function of th.e seal package is (rigure 5) to provide a pressure break-down from system pressure conditions to ambient and keep reactor coolant losses to a minimum.
The shaft seal system consists of a series of three water-lubricated face seals in combination with suitable external systems which effectively control and monitor the upward flow of the high-pressure reactor coolant during a loss of injection water occurrence. During normal operation, f 130 F injectjen water at a higher pressure than loop coolant water enters the pump through a connection on the thermal barrier flange at a rate of about 8 gpm (Figure 6). About 60 percent (5 gpm) of this injection water flows downward through the thermal barrier / heat exchanger and into the primary system. This prevents the primary system coolant from entering the seal area of the pump. The remaining 40 percent (3 gpm) of the injected water enters the No.
I seal.
67217/406/003
'ATS/FLAh'T SYSTEMS - RCPs 3
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NTS/PiANT SYSTEMS - RCPs PAGE 9 0F 21 The No. I seal is a hydrostatic 611y-balanced film-riding face seal which produces about a 2250 psi pressure drop. In addition, the design characteristics of the seal faces and ,their balancing are such that the seal film controls seal flow over a broad range of differential pressures. The primary components of the seal I
are a runner which rotates with the pump shaft, and a non-rotating seal ring which is attached to the seal housing. The ring and the runner each have an aluminum-oxide faceplate clamped to a Type 304 SST holder. .
NUMBER ONE SEAL The No. I seal is a " controlled leakage a seal because the leakage through the seal is predetermined and controlled, by ensuring that the gap between the seal ring and seal runner is always held to a constant value. This is achieved by designing a stable balance of hydrostatic forces on the ring.
To understand the concept, and to see why the gap between ring and runner stays constant, it is convenient to ,
examite the forces on the ring by dividing them into
" closing f orces -
those forces tending to close the gap, j and " opening forces" - those forces tending to open the gap
- (Figure 7). A constant closing force proportional to the pressure differential is imposed on the upper surface of the ring. This may be shown as a rectangle on a force balance diagram. At equilibrium, an equal and opposite force acts-on the bottom surface of the ring - tending to open the gap.
If the seal faces were ptrallel, this force would vary linearly along the radius, from the high pressure to the low. However, there is a tapered section toward the outer edge of the ring. This causes the pressure at the breakpoint to be higher than it wo0ld otherwise be. So the force diagram for the opening force departs from a true l
1 87227/406/003 l
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nce rwa cacn:MS - RCPs.. PAGE 10 0F 21 triangle. If the gap tends to close, i.e., the ring moves downwards, the percentage reduction of area in the parallel section is greator than in the tapered flow passage. The resistanen to flow in that section increases more rapidly that it does in the outer passage. Thus, the absolute
[ pressure at the breakpoint will increase. This distorts the force balance dir. gram so as to give a slight increare to the
- opening force and a slight decrease in the closing force.
This tends to move the ring in the opening direction. ,
A similar argument will show that if the gap tends to open, the opening force will decrease and the closing force will ,
increase -
again tending to restore the ring to its equilibrium position.
t If the pressure in the primary loop is decreased, the shape of the force balance diagram will not change. The actual value of the forces will naturally decrease. As the pressure becomes loSm . the weight of the ring becomes a larger part of td: 7.t esing a force. At
' pressure differentials below about 1.L psid the hydrostatic forces become .asufficient to float the seal. It is not permitted to operate the pump at No. 1 seal differential pressures of less than 200 psid.
l NUMBER TWO SD1 1
Host of the low-pressure fluid leaving the No. I seal is diverted by the No. 2 face-type rubbino seal back to the injection control system. The pressure drop across the No.
2 seal is about 25 psi; however, in the unlikely event of a No. 1 seal fsilure, the leekoff between the No. 1 and No. 2 is closed, and the No. 2 seal converts to a film-riding face seal. The rubbing-face type seal, consisting of a Graphitar 114 insert axially captured between a seal ring and a roteining ring with spring loaded pins. Both rings are made L from 304 SST forgings, and are attached to the No. 2 seal E7217/406/003 1
__ . . . - - . - - ~ -- - - - - - - -
MiD/ PLANT SYSTD4S - CCPs_ _ _ , -;
' PAGE 110F 21 housing.
The insert rubs on a chrome-carbide-coated 304 Ss7 !
, runner which rotates with the shaft. DJring normal I operation, the ring etnd runner provide a rubbing seal. If the No.1 seal fails, however, the pressure distribution on the No. 2 runner causes it to react against the spring and
[ deflect in such a way as to provide a film-riding face seal. .
The flow from the No. 2 seal is diverted by the No. 3 seal i
, out through the No. 2 leakoff to the reactor coolant drain tank.
NUMBER THREE SEAL The No. 3 seal is also a rubbing-face type of seal, consisting of a Graphitar-114 insert radially shrunk to a seal ring and axially captured with spring loaded pins.
This assembly is axially leaded with externally adjusted springs, so that the insert rubs a chrome-carbided-coated runner which rotates with the shaf t. The rings and runner are made of 304 stainless steel forgings.
The No. 3 seal has a separate water injection line. The Reactor Hakeup System supplies the respective RCP Seal
- Standpipe. The water from the standpipe is then injected -
into an annular slot in the seal insert and escapes through >
the inner and outer dams in the insert. The outer dam leakage flows out the No. 2 seal leak-off to the reactor coolant drain tank; any Anner dam leak-off which is not vaporized by the high temperatures will flow out the No. 3 leakoff to the cent. sump. The purge water helps prevent the accumulation o~ beric acid crystals in the atmosphere side of the No. 3 seal and around the seal housing.
l B7217/406/003
.,,
- llITS/PIANT SYSTEMS - RCPs PAGE 12 0F 21 40 HDTOR SECTION DESCRIPTION (Figure 8)
The motor is a vertical six pole, Class B Thermalestic Epoxy-insulated, squirrel cage induction motor of drip-proof construction. It is equipped with upper and lower radial e bearings, a double Kingsbury thrust bearing, flywheel, thrust bearing oil lift system, and a coupling flange. The motor is also equipped with bearing and winding temperature sensors, bearing oil coolers, oil level limit switches, an anti-reverse rotation device, and motor air coolers.
ROTOR The rotor is built of stacks of low-loss electrical sheet steel laminations periodically fitted with vent spacers.
Each lamination is a complete circle capable of supporting the centrifugal forces encountered. A finger plate and clamping plate on each end apply and maintain pressure on the laminations to keep the rotor tight.
The equirrel cage windings consist of copper alloy bars l snugly fitted in rotor slots and secured by swaging to climinate rotor bar vibration. The bars are butt brated in rnachined grooves to short-circuited connection rings.
The motor shaft is made of high-grade forged steel. The lower guide runner is forged for maximum stability. A flange at the lower end of the shaft serves as the coupling to the pump, i The internal parts of the motor are cooled by air. 2ntegral vanes on each end of the rotor draw air through cooling slots in the motor frame. This air passes through the motor with particular emphasis on the stator end turns. It is then ducted to the containment atmosphere, through air coolers, which are ceoled by component cooling water.
87217/406/003
__ _ . _ - _ . _ l. -
E2S/Pl. ANT SYSTEMS - RCPs 1
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,, , NTS/PI. ANT SYSTEMS - RCPs PAGE 13 Cr 31 i
l UPPER BEARING The upper bearino (Figure 9) is a combination l
double l Kingsbury type thrust bearing (suitable for up or down !
thrust) and a radial guide bearing. The babbitt-on-steel !
thrust bearing shoes are mounted on equalising pads which '
distribute the thrust load to all shoes. The radial bearing >
is a babbitt-on-steel, pivoted-pad bearing positioned by jackscrews and held in place with lockplates. The upper '
radial bearing and thrust bearing operate against an alley i steel journal and thrust runner combination which is shrunk on the shaft. The entire upper bearing assembly is located in the upper oil pot. A heat exchanger mounted on the side of the motor cools the oil using CCW. Oil is circulated through the upper bearings and oil cooler by means of series of passages drilled in the thrust runner, which act a s 'a centrifugal pump.
In order to reduce etarting torque, the thrust bearing shoes are fed with oil from the oil lift system before starting l
the motor. The cil alifts" the thrust shoes away from the l thrust runner and provides a .001 to .003 oil film between f the runner and fl. hoes at the same time, high pressure oil is sp;ayed to the guide bearing chamber for lubrication of the upper radial guide bearing. The thrust bearing oil lift system includes a 10 hp, drip proof, three-phase, 60 cycle, 460 volt, 1600 rpm motor; an oil pump; pressure gauge; pressure switch; check valves; filter; relief valve; and orifice blocks. The oil lift motor and pump are mounted j externally on the upper part of the motor casing. There is I a permissive interlock in the motor starting circuit that does not allow the motor to be started until the oil lift pressure has reached 600 psi. After the pump has been in operation for about one minute the oil lift pump may be "
switched off. It is not required during pump stopping. The 67217/408/003
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NTS/ PLANT SYSTEMS ~~ RCPs PAGE 14 0F 21 Iower thrust bearing takes the weight of the rotating parts when the reactor coolant loop is at low pressure. As the loop pressure increases, the unbalanced force on the No I seal causes the shaft to lift and transfer the thruct to the upper thrust bearing. By the time loop pressure is i
sufficient to allow pump operation all the thrust is acting on the upper bearing, which is the normal operating condition. The only time that the lower thrust bearing is in use is when the motor runs uncoupled from the pump, and the weight of the motor rotating parts is acting downwards.
(Fig. II-1.4.10)
LowrR GUIDE BEARING The lower guide bearing is a babbitt-on-steel, pivoted pad guide bearing, positioned by jackserews and held in place with lockplates. The bearing operates against a .5% carbon alloy steel journal. The entire lower guide bearing assembly is located in the lower oil pot which also contains an integral heat exchanger for cooling the bearing. This oil pot is an integral part of the lower bracket.
l FLYWHEEL l
In the event of plant blackout, it is necessary to ensure a continuation of coolant flow through the reactor core for a short while af ter reactor shutdown. For this purpose each.
reactor coolant pump has a flywheel keyed to its shaft, and located above the motor upper bearings. The flywheel provides approximately one minute of flow coastdown to provide DNB protection during the early stages of station blackout when the decay heat level is high.
l 1
87217/40E/003 l
...... .. . .es.;- w o- - ^
~ } AGE 15 OF 21 5.,
ANT 1-RDTRSE ROTATION DEVICE ,
In a multi-loop plant, de-energitation of one t
or more reactor coolant pumps while another pump, or pumps are running causes a reverse flow through the inactive loops.
' This reverse flow tends to turn the de-energised pumps ,
backwards. Although no mechanical damage would result from such reverse rotation, if an attempt were made to start a pump in this condition, excessive starting currents would be drawn for an excessive time, resulting in over-heating of the motor. To prevent this reverse rotation, each pump is equipped with an anti-reverse rotation device (Figure 10).
The anti-reverse rnechanism consists of five pawls mounted on ,
the outside diameter of the flywheel, a serrated ratchet plate mounted on the rnoter frame, a spring return for the ratchet plate, and two shock absorbers. After the motor has come to a stop, one pawl will engage the ratchet plate and, as the rnoter starts to rotate in the opposite direction, the i
ratchet plate will also rotate sligh:1y until stopped by the shock absorbers. The rotor will remain in this position until the motor is energized again. After the motor has started to rotate, the ratchet plate will be returned to its original position by the spring return. When the rnoter is '
l started, the pawls will drag over the ratchet plate until the motor reaches approximately 70 rpm. After this time, centrifugal force will keep the pawls in an elevates position.
STATOR The stator core laminations are made from high-silicon electrical sheets coated with alkoplus for insulation.
Stacks of laminations separated by air vent spacers are held in place by studs and clamped by steel end plates.
l B7217/406/003
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., ., MTS/ PLANT dYSTEMS - RCPs PAGE 16 0F 21 !
The stator windings are made of insulated copper wire fitted into slots in the core. The ends of the windings, which extend beyond the slots, are braced by an insulated support ring and are separated by non-woven polyester felt packing I
to withstand the mechanical forces associated with full-voltage starts.
The entire stator core and windings are insulated and are moisture resistant. A solid epoxy resin strengthens the bracing system of the windings. This resin is susceptiMe to radiation damage at levels of 100 rads /hr. Normal radiation levels are less than 50 reds /hr; therefore, no deterioration is expected.
l 5.0 RCP INTERFACE SYSTEMS COMPONENT COOLING WATER SYSTEM (Figure 11)
The Component Cooling Water System supplies water for the rnoter air and oil coolers and the pump thermal barrier heat exchanger. Water is normally supplied to the pumps from the component cooling water system via ,
pump supply manifold located inside the containment. Two series check valves for each RCP prevent back flow of reactor coolant liquid through the CCW system if a rupture of the thermal barrier heat exchanger should occur. Piping from the check valves to the flange connection on the pumps is designed for high pressure since it may be subj ected to reactor coolant system pressure. The cooling water then passes through the heat exchanger, past flow and temperature elements, and traough a motorized valve. This valve is controlled by a signal from l the flow element or the temperature element upstream. If a rupture of the heat exchanger should occur, high flow (75 l gpm) or high temperature (200 F) would result and the 67217/40E/003 1 - - . - - . - .-
.i 5
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NTS/PIANT SYSTEMS - RCPs PAbb 17 OF 21 f 6
motorized valve would close isolating the thermal barrior <
cooling flow. Therefore all piping from the motorized valves to the thermal barrier outlets may be subjected to '
reactor coolant system pressure. A safety valve is provided between the check valve and the first stop valve following
- J the thermal barrier heat exchanger to relieve excessive pressure that may be caused by heating. The relief valve 4
relieves to the downstream side of the valves.
CLOSE/ AUTO /OPEN (momentary contact, S.R. to AUTO switches for each valve are located on CP-004.
SEAL INJECTION / LEAKOFF SYSTEMS (Figure 12) g Injection water is supplied to the reactor coolant pump from i
the chemical and volume control system by the charging pumps. The injection flow (8 gpm) enters the pump in the '
thermal barrier region where the flow splits with 3 gpm passing upward through the controlled leakage seal package and returning to the chemical and volume control system.
The remaining 5 gpm passes through the thermal barrier heat exchanger and into the reactor coolant system as part of the reactor coolant system charging flov -
.eing discharge
~
from the charging pumps, the injection ilow passes through L the injection filters and manifo10 to all the reactor coolant pumps. Two filters are s, , ted wl to the-containment which permits flater che,e u. ~ interrupting injection flow. Each pump is provi..,- 4 r r; ;ifice type i flow transmitter and indicator foliova, sy _a adjustable valve, both of which are located outs.tse too conttinment so ,
that injection flow may be adjusted. Downstreal of the containment penetration, a check valve prevents back flow from the reactor coolant system should .inj e ction flow be lost.
67217/408/003
5t RCP Sealinjection System i
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.,, itTS/PIANT SYSTEMS - RCPs PAGE 18 OF 21 The No. I leakoff system provides the necessary flow circuit and instrumentation to assure satisfactory operation of the No. 1 controlled leakage seal. The low pressure No. 1 leekoff flow originates on the low pressure side of the No.
1 controlled leakage seal. 'The leakage (3 gpm) passes
?
through a remotely operated valve, through a flow orifice with two flow transmitters and then combines with flow from the other pumps before returning to the chemical and volume control system volume control tank. Two transmitters are required to satisfactorily record the flow over the anticipated range. A pressure differential transmitter is provided, which indicates pressure drop across the No. 1 seal. This has a control board indicator and a low differential alarm, in the control room. i The No. 2 seal leakoff of ~3 gph flows to a loop seal and a ;
flow orifice with flow -indicator switch, which alarms on I high flow.
It then drains to the reactor coolant drain tank.
The No. 3 seal in$ection rate is approximately 800 cc/hr.
Reactor makeup water is injected between - the two faces of the seal, and is supplied from-a standpipe located above the No.- 3 seal connection. The standpipe has an overflow, a high level alarm, and a low level alarm. It is refilled from RMW. The standpipe fill valves are controlled by a 2-position switch (CLOSE/OPEN) on CP-004 (one per pump). The leakoff from No. 3 seal drains to the containment sump (400 cc/hr) from inner dem and to No. 2 seal leakoff (400 cc/hr) from outer damp.
l l
67217/40E/003 l
l
- .,WTS/PIANT SYSTEMS - RCPs PAGE 19 0F 21 6.0 RCP OPERATIONAL LIMITS STARTING PREREQUISITES The following-RCP related conditions must be satisfied prior
. to starting a RCP:
O o Control power available o oil lift pump motor running > 2 min
- o oil lift pressure greater than or equal to minimum (600 psig) o No. 1 seal leakoff greater than 0.2 gpm o No. I seal differential pressure greater than 200 psid .
RCP HOTOR STARTING LIMITS The following RCP motor limitations are applicable to the
, 9 tart of any RCP:
l j- .o Restarts: Two successive restarts permitted provided ,
motor is allowed to coast to a stop between starts. A-i M third start may be permitted when the winding and core
'D have cooled by running for a period of 20 minutes, or -
by standing idle for 45 minutes.
1 o Only one pump to be started at any one time.
o The reactor coolant pump should be started only after the oil lift pump has been running for two minutes.
The oil lift. pump should continue to run for a minimum of one minute after the RCP has been started.
l 1
l l
87217/408/.003
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' ' . .. '., HTS / PLANT SYSTEMS - RCPJ PAGE 20 OF 21 RCP TRIP CONDITIONS - NORMM., OPERATIONS
[During normal operating conditions any of the following ,
conditions require a RCP trip to avoid continual degradation of the situation which could potentially result in damage to the RCP:
l o High or low bearing oil level alarm '
o- Hotor bearing temperature greater than 200 F ,
o el seal inlet temperature greater than 135 F, .or high inlet temperature following a el seal leakoff flow high alarm o simultaneous loss of both seal injection and component cooling which cannot be restored within one minute '
i o Less than 200 psid #1 seal o Less than 5 psig in the volume control tank, might mean no flow to #2 seal o Pump shaft vibration greater than .020 inches f o No. I seal leakoff less than 0.2 gpm RCP TRIP CONDITIONS - ACCIDENT CONDITIONS During accident conditions, there are some situations which warrant the trip of RCPs if they are running. The purpose el tripping the RCPs during accident conditions is to prevent excessive depletion of RCS water inventory through a smell break in the RCS which might lead to severe core uncovery if the RCPs were tripped for some reason later in the accident. i 67217/408/003
~ ~'
urue>vutumrufuetssa - uuvu r ws, n ur 21 since it is most desirable to have RCPs in operation at:all times, except for the small break LOCA, the first criteria which must be' met that allows RCP tripping is the establishment of high ' head safety injection (HHSI). With HHSI established, uncovery of the core via a small break
? LOCA is virtually impossible.
since it may not be possible to determine the existence of a small break LOCA under other accident scenarios, it is necessary to address another parameter value which gives an unambiguous indication that RCPs need to be tripped. This parameter is RCS pressure and its value has been established' based on analysis of a number of various accident scenarios.
The resultant RCS Pressure is based on the highest SG safety value setpoint plus the pressure differential between the SG l and the point of RCS pressure measurement plus instrument L
inaccuracies.
The current RCP trip criteria for use under accident conditions at STPEGF are both of the following:
1
7.0 REFERENCES
l STPEGS FSAT, Volume 8 and 16 l l
NSS Reactor FLjid System Design Information - TGX Reference Operating Instructions - TGX-Model 100 RCP Technical Manual .
WOG EEG Executive Volume, Revision 1, 9/83 67217/405/003
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,-Question 9:
Please provide analysis summaries for sequences 6 and 8 which are missing from Table 1 (Analysis of Top Ranking Sequences)..
Response
See attached descriptions for sequences 6 and 8.
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Anotyeis of Adfitionel Top-Ror*Ing Segumees to steen Core Daunge
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Segwice Etw Sollt Event Description paren Fregumey . 'Fractiam Reference (PSA)
(par yeer) f* ntIfier initiating Event; Portlet loss of Mein Feedseter Floer 1.1 x 10+0 Ptsw W Chapter T.6 Systese feltures to System Fellures - Felture of 2.7 x 10-6 Out Chapter 15.4 Following tong-Term retor Actions To initleting Event 5tabilire t Plant Recovery Actions #ene N/A N/A W/A Totet Se g ence Fre m ency 2.2 x 10-6 i
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Question 10:
Why was ' feed and bleed not . considered in sequences 10, 14, 17, 18, and 197
Response
Sequence 10 -
feed and bleed not considered because of the
-unsuccessful recovery actions that have already been i included in the sequence- (recover of fsite power, one of two diesels, or the turbine driven ATW pump).
Sequence 14 - Similar to sequence 10 Sequence 17 -
Similar to sequence 10 (one diesel instead of two).
Sequence 18 - Similar to sequence 10 Sequence 19 -
It appears that feed and bleed is a viable option for this sequence. We will investigate further and provide additional response. The s equence frequency is conservative without feed and bleed.
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Question 11:
In Sequence 16,'is it assumed that the PORV or a safety valve on the affected steam generator fails open when water is ,
passed? If so, does OAA included cooldown? What is the difference between OAA and'oCQ in Sequence 207 Responset Sequence 16 represents the operator failing to depressurize the RCS with the PORVs on the intact steam generators to that of the ruptured steam generator and failing to cooldown and depressurize the RCS to RHR entry conditions within 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.
This . sequence covers the possiblity of a PORV or safety valve sticking open on the. ruptured steam generator, but represents .
successful isolation.
Sequence 20 represents the operator- failing to isolate a stuck open PORV or safety valve on the ruptured steam generator and failing to provide long term decay heat removal via RHR cooling.
Split fraction OAA is equivalent to HERC1 per Trble 3.3.3-12 of the PSA Summary Report. HERC1 is defined as operator fails I
to cooldown and-depressurize the RCS to RER entry conditions and.
. init'inte RHR cooling per PSA Table 15.5-1. HERC1 does not include any hardware contributions.
Split fraction OCA is~ defined in Appendix F, Book 17 of the PSA as operator fails to start at least one of three available RHR trains. 'OCA includes both hardware and human error ,
contributions. The human error contribution is represented as t
HEOC01, which is the operator failing to align and start closed loop RHR cooling. OCA does not include the operator action.to cooldown and depressurize the RCS. This action is modeled separately in the SGTR event tree under top event OD, which was successful for Sequence 20.
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E Table 3.3.3-12. Rn u.;.3 Actiotes Htsman Error Rates q
E M Designator Home of Distrilwthm fuleen Vergence 80edlen o Percoatee Percentile D
HERC1 Cooldown send Depressurire RCS To RHR Conditions 2.9042 ~ 2.21-03 1.9443 f .40-02 97842 j t.
2.08-03 1.4542-y 2. HERC2 Isolate Steam Generator by Cloemg Manual Block Valve 4.31-03 4 88-05 2.88-04
- 3. HERC4 Operator Align M/U To RWST for HMSI 9 82-04 2.54-06 65745 4.75-04 3.3243
- 6. HERAt Operator Closes PORV Block Valve To isolate the t.OCA Path 95243 2.3844 6.37 04 46143 32142
- 7. HERAS Operator Restores Flow Path for Turtine-Dreven AFW Pump 7.1742 1.35-02 4.7943 3.47-02 2.42-01 Locally 8 HERA7 Operator Starts Standby ECW. ECH and. CCW Trams After 6.1642 9.97-03 4.1243 2.98-02 2.0841 Loss of SSPS Due to Fire
- 9. ZHEPR1 Operator Action To Recover Electric Power After Station 59643 9.33-05 3 98-04 2.88-03 2.0142 g Blackout with AFW and PD Chargmq Pumps Avariable 3.1642 2.29-01 1.00 + 00
$ 10. HEOSO4 Seesmic Event; initiate Smoke Purge and Open Doors 4 73-01 58841 h 11. HECH03 Seismic Event Start Tech wcal Support Diesef Generator and 9 70-02 2 47-02 64943 4 70-02 3 27-01 the PD Pump
- 12. HECH04 Sessmic Event Start the PD Pump 93443 2.29-04 62544 45243 -3.1542
- 13. HEORf1 Seismec Event Manually Start Equipment After Load 1 46-01 5.57-02 97343 7 04-02 49141 Sege mce Fasts 14 HEOB02 Seismic Event Open Two of Two PORVs for Bleed and Feed 1.91-02 9 55-04 12703 92343 64302
- 15. HEOR09 Operator Trips Reactor and Manually Starts AFW (No MFW) 5 46-02 78243 36543 ' 2.64-02 18441
[ Note: Exporential notation is shown in abbreviated form; e g 2.90-02 = 2.90 x to" E
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Question 12.
What is the basis for assuming pressurizer PORVs are required to open in sequence 15? Is it verified that one feedwater train i with no SG PORV available due to loss of AC power but with all SVs available requires pressurizer PORVs to open?
Response
This issue is discussed in Section 3.1.2.1.1 of the summary report (portion attached).
"For event sequences in which secondary steam relief is substantially delayed or reduced (e.g., if only one steam generator PORV or safety valve opens), analyses for plants of similar design to the' South Texas Project indicate that it is quite likely for RCS pressure to exceed the pressurizer PORV setpoint; 1.e., 2335 psig. In these scenarios, the pressurizer PORVs must first open to relieve ,
the transient pressure spike, and they must reclose to prevent a continuing loss of RCS inventory."
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temperature at the no load T,yg setpoint by passing steam to the condenser, if the main condensor is not available, secondary steam relief is achieved with the steam generator PORVs or safety valves.
It has been shown in the EOP Trip Setpoint Study that, following a reactor trip, the main feedwater control and bypass valves close, Isolating flow from the main feedwater system.
This isolation occurs from a translent cooldown to the RCS low T vg setpoint caused by normal feedwater supply and injection of cold water from the AFW system when steam generator levels shrink below their low low level setpoint. After the main feedwater isolation valves close, AFW provides the normal supply for steam generator makeup, with steam relief continuing to the main condenser or to the atmosphere.
For most transient event Initiators, such as a reactor trip or turbine trip, the pressurizer PORVs are normally not challenged to relieve RCS pressure. However, for event sequences in which secondary steam relief is substantially delayed or reduced (e.g.,if only one steam generator PORV or safety valve opens), analyses for plants of similar design to the South Texas Project indicate that it is quite likely for RCS pressure to exceed the pressurizer PORV setpoint; i.e., ?,335 psig, in these scenarios, the pressurizer PORVs must first open to relieve the transient pressure spike, and they must then reclose to prevent a continuing loss of RCS inventory.
For a general transient event without ESFAS actuation, the operators take manual centrol of AFW flow to stabilize secondary inventory after normal steam generator levels are restored.
If an ESFAG actuation occurs, automatic controls maintain AFW flow between 540 to 600 gpm to each steam generator until the operators reset the automatic signals, manually reduce flow, and maintain normallevels as the decay heat rate falls. The reactor coolant pumps normally continue to operate, and the plant is maintained at hot standby, ready to return to power when the problem'that caused the reactor trip is identified and resolved. RCS Inventory is maintained by balancing charging with letdown flow and by maintaining RCP seal injection flow to ensure continued seat integrity.
The preceding paragraphs briefly describe the normal plant systems and operator responses after a plant trip. The event sequence diagram also displays a number of alternate scenarios that may occur if the normally operating equipment malfunctions. Many of these scenarlos include only minor deviations from the normal plant response that ultimately result in a stable plant configuration. Severe equipment failures or operator errors may cause accident sequences in which the end result is core damage.
The general transient ESD is shown in Figure 3.1.2 2. The following paragraphs briefly describe each event modeled in the ESD. The event numbers correspond to the numbered blocks In Figure 3.1.2 2. The success criteria for each event block are provided in Table 3.1.2 2. The entering boundary conditions to the model are that an initiating event that require an automatic plant shutdown has occurred.
- Event 1 - Reactor Trip. The first block models the response of the reactor protection system to automatically shut down the reactor. The success path from this block Indicates that a sufficient number of control rods have been automatically inserted to make the reactor suberitical. Major equipment modeled by this event block includes the analog trip slonal transmitters, the reactor protection logic channels, the reactor trip breakers, tne control rod drive mechanisms, and the control rods. All transient initiating events evaluated in this study are sufficiently severe to produce an automatic reactor trip 3.1.2 3 Pickard Lowe and Garrick, Inc.
NHLP1N0052 051989
Question 13 In sequence 20, " failure to isolate stuck open PORV or )
safety valve on affected steam generator " has a mean of '
- 2. 4 x 10" . Pa+;e 5.4-108 (Event SL) implies all' 5 SV's in addition to the PORV, open on the affected steam generator.
Table 7.3-3 page 9 provides a mean for a SV failing to reclose of 2.87 2.5 xx 10~
10- 2.and a' mean How is 2.4forxthe PogV 10~ failing to reclose calculated? Does of it include failure to close the PORV block valve? Should the event description for split fraction OCA exclude "Cooldown and" since p.5.4-108_ states that cooldown has occurred for event oC7
Response
Top ' event SLA includes failure of any one of five safety valves to reclose plus failure of the PORV to reclose and the operator fails - to isolate given failure to reclose. See system analysis for secondary steam side isolation Section J (Assumptions), the system failure equations for top event SLA (event HEOSL1) and Table 15.4-53.
t The top event description should not include the words "Cooldown and".
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ms AS essociated with the Dtse Solenoid Vetwee are also 1 ms As deenergized thue wenting the MS!V elr cytInder. Note 3 S mS AS on the Schematics indicates either ESFAS frein A or S ms AS ESFAS Train B for the MSIV dg solenoid volves (e.g. S m$ AS Ff 7&i&C & FTT41&O); however, the drowing does not S ps AS Indicate eAether or not the two ESF releys shown ere S ms AS associated with, for esemple, ESFAS frein A per Note 3, S
{
l ps As or iAether one retey is associated with ESFAS Train A S MS AS and the other with ESFAS frein S. Although the Logic S m$ AS drawing indicates the Otsup solenold vetwes ending in S ms AS e %= ore essociated with ESFAS frein A, and those S-as AS ending in a "O" are essociated with ESFAS Train S, it S ms AS ogveers, from the schematics, that tieth ESFAS actuation S m3 AS treins inteefece with each NStv damp solenoid volve. S MS AS Thus, for enesote, the E83&A relay when deenergf red S as AS witI deenergire the solenoid for both "C" and T
- day S MS AS solenoid volves and likewise for the K83&S retoy. For S m$ As this onetysis it will be asstaupd that ESFAS A releys, and S 'i ms AS simiterly ESFAS S reteys, will oeenergire both MSiv "C" S as AS and "D* solenold esp vetwes. S ms AS S
ms As o the NSIV Bypass footetten velwes will not be included in S ms As this onetysis since they are only used during stortie $
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N4RL1D= DFRL1*20RL1D*2CRLID*2ORL1D*2TRL1D 1 CLOBAL ESF RELAY FAILURE E834 E848 (SWOCE OWLY)
Y1dSOD= (1-!TTVSO+1TTVSO*TTTS/TREFS)*2TVSOD S StuCLE enc SOV FAILURE TO NFER TO FAILED PO$tTIOS Y2VSOD= DFV50*(1-ZGVS00)*2BV50D*ZTVS00/3 S DoutLE ENC SOV FAILURE TO NFER.TO FAILED POSITIOW Y3VSODo DFV50*(1-ZDVSOD)*2CVSOD*28VS0D*2TVSOD/3
- TRIPLE Enc SOW FAILURE TO NFER TO FAILED POSITION T4WSOD= DFVS0*2DVSOD*ZCVSOD*20VSOD*ZTVSOD S CLOSAL ENC SOW FAILURE TO XFER TO FAILE9 POSITION M1VSOD= (1-ITTV50*lTTVS0*TTTS/TREFS)*2TVSOD .S SINCLE RSiv SOV FAIL TO MFER TO FAILED POSITIOW K2VS00= DFVS0*(1-2GVSOD)*2SVSOD*ZTV500/7 S DOUBLE MSiv $0V FAIL TO MFER TO FAILED POSITION M3VSOD= DFV50*(1-2DVSOD)*ZCVSOD*2BVSOD*27Y~..! S TRIPit NStV SOW FAIL TO XFER TO FAILED POSITIO#
M&VSOD= DFVS0*2DVSOD*2CVSOD*Z5VSOD*ZTVSOD S CLOSAL WStv SOV FAtt TO RFER 70 FAILED POSITION DFVSO = (1-DTTVS0*0TTV50*TTTS/TREFS) S DFRL1 = (1-DTTRL1) S ESFAS RELAT $NOCE FAILURE TERN
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Question B.1: i Are frequency distributions (as opposed to point estimates) rigorously propagated from component level through system level to sequence quantification?
Response
Yes. Discrete probability distributions (DPD) -for the basic. parameters to be quantified in each EQS file are used to produce DPD's representing each event tree split fraction through the use of the RISKMANS. software using Monte Carlo simulation.
The event trees are quantified using the distribution mean f requencies and core damage frequency. is determined. The sequences (of split fractions) comprising the dominant sequences are then quantified using Monte Carlo simulation.
Although this- is also usually applied to the quantification of external event sequences, the external event contribution to the STPEGS core damage frequency were determined using point estimates. The only exception is that the control room fire scenario frequencies were determined using the STADIC4 computer code using Monte Carlo simulation. Point estimates were l utilizad for the quantification of the seismic scenarios due to the fact that the EPRI and Lawrence Livermore Lab seismic hazard curves were only available a few days before the completion of the report. -
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a Question 2 (PRA Methodology)
How can system failure data as calculated by the PSA software be easily checked for accuracy?
Responses Assuming log normal distributions and calculating the parameters au and sigma for the distributions, combining nu and signa, then developing the mean and variance for the combined zu and sigma allow a rough check on the values presented.
Attachment A is a very good rough check also.
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Question 3 (PRA Methodology):
How are partial system successes and failures handled with )
respect to other systems which share components? For example, if systems A and B both share component C1, suppose system A succeeds given loss of C1. How is the failure of B given success p
of A and loss of C2 handled?
Responser If a component is shared among several systems it is typically included specifically in the plant event trees (e.g.
the RWST) . Top events CD and AF in the general transient tree show how the specific example in the question is calculated. CD is defined as ATW and secondary cooling (Steam generator PORV's). Top event AF is defined as ATW given steam generator PORV's have failed. The system failure equations in the ATW system analysis show how these top events were quantified.
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