LD-91-071, Responds to NRC Requests for Addl Info for Review of C-E SSAR-Design Certification Rept.Proposed Revs to Ssar Encl
| ML20086U201 | |
| Person / Time | |
|---|---|
| Site: | 05200002 |
| Issue date: | 12/24/1991 |
| From: | Erin Kennedy ABB COMBUSTION ENGINEERING NUCLEAR FUEL (FORMERLY, ASEA BROWN BOVERI, INC. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| LD-91-071, LD-91-71, NUDOCS 9201070251 | |
| Download: ML20086U201 (88) | |
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ASF.A BROWN BOVE Al
- December 24,1991 LD.91-071 7.
Docket No. 52 002
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- U.S. Nuclear Regulatorv Commission i Attn: Document Control' Desk Washington, DC 20555 Sub)ct:' Response to NRC Requests for Additional Information _
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References:
A) Letter, Reactor Systems Branch RAl's, T. V. Wambach (NRC) to E. H. Kennedy (C-E), dated Februaiy 15, 1991.
B) Letter, Reactor Systems Branch RAl's, T. V. Wambach (NRC) to . 1 E, II. Kennedy (C-E), dated May 13,1991. ,
TC) Letter, R:idiation Protection Branch R Al's, T. V. Wambach (NRC) ta E, lt Kennedy (C E), dated August 3,1991.
D) Letter. . Materials and Chemical Engineering Branch RAls T. V.
Wanbach (NRC) to E.11. Kennedy (C E), dated August 8,1991.
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. E) Letter, Ret.ctor Systems Branch RAl's, T. V. Wambach to E.11.
Kennedy (C-E), dat-d August 21,1991.
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IF) ' Letter, Plant Systems Branch RAl's, T. V. Wambach (NRC) to E.11.- >
Kenbedy (C-E), dated October 10,1991.
-Dear Sirin EReferences A) through F) requested additional information for the NRC staff review of the 7 Combustion Engineering Standard Safety Arn!vsis Report- D: sign Certification (CESSAR-
-DC).- Enclosure I to thi.s letter provides our raponses ta a number of questions from those -
references. Enclosure 11 provides corresponding revisions to CESSAR DC.
Wh Ar3B Cornbustion Engineering Nuclear Power
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U.S. Nuclert llegulatory Conunissic.n 1.D 91071 ,
Decensber 24,1991 l' age ..
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Should you have any questions on the enclosed insterial, please contact me or Mr. Stan Ritterbusch of my staff at (203) 2F'.5206. j Very :ruly yours, COMilUSTION IINGIN!!!!!(ING, INC.
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- 11. I1. Kennedy Manager Nocicar Systems 1 icensing lilIK:lw linclosures: As Stated .
cc: J. Trotter (I!PRI)
T. Wambach (NitC) 1 k
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IllISPONSE TO NRC RIIQUlISTS FOR ADDITIONAL INFORMATION i
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. i Q42511CD 440.32 CESSAR-DC Section 5.2.2 states that the design basis incident for sizing the primary safety valvos is a loos of turbine-gonorator load. Figure SA-3 indicatos that for the worst caso loss of load incident, the reactor trip signal is generated at 5.1 seconds following the event 4.nitiation.
Ilowever, the type of signal which generates the reactor trip is not identified in CESSAR-DC. Provido the results of the analysis, including the soquence of events, of the design basis incident for sizing the primary safety valves.
Confirm that the reactor trip la initiated by a second safety-grado signal from the reactor protection system por the acceptance critoria in the Standard Review Plan (SRP)
Section 5.2.2.
lies 201MLL.4 4_Ed2.
The reactor trip is generated by the second safety-grado signal from the reactor protection system. The first safety-grado signal and all control grado reactor trip signals are ignored. The sotpoint of the first safety-grado trip signal, generated by the Reactor Protection System (RPS) on high primary pressure, is 2445 psia and that of the second, generated by the Coro Protection Calculator (CPC) also on high primary pressure is 2464 psia. The results of the analysis and the sequence of events are presented in Appendix 5A and Figure SA-3, respectively, of Amendment I to CESSAR-DC.
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Qugstion 440.48 Provido a SCS pump characteristic curve for the staf f review. Specify the available and required not positivo suction head for the SCS pumps.
Eggoonse 440.48 An final SCS pun? characteristic curve for System 80+ will not be avcilablo.until the procurement phase when the actual pumps are procured. Howevor, a-range of typical SCS pump characteristic aurves is provided in the attached figure.
Those curves include the typical shutof f, design point, and runout chare.ctoristics which are required for the SCS pump to meet the shutdown cooling functional design bases in CESSAR-DC Section 5.4.7 and the containment spray functional design bases in CESSAH-DC Section 6.5.1.
The minimum not positivo suction head available (NPSHA) for the SCS pumps is typically 22 foot at the design point. The not positive suction head required (NPSHR) is typically 20 feet. For System 80+, the NPSHR will be specified to be less than HPSHA furing the procurement phaso.
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QRqation 440.53 Expand the SCS failure modos and offects analysis including potential electrical single failures and failures of interlocks on the pressuro isolation valves. What actions are necessary and where must they bo performod under those conditions? Describe the proceduros which the operatorn will need to uso following a postulated failure such as !
discussed above.
Enan9Aa.e_440.53 The SCS consists of two indopandent trains, each of which is ,
capable of bringing the ple*? to cold shutdown. Each SCS i train includos a pump, a h*at A.9hange*, and associated suction and dischargo valvan, as O-s*J. bod in CESSAR-DC Section 5.4.7. The followJng paraq' .phs summarize the ,I potential impacts of single 9)(ct #.sn1 failures and single failures of interlocks on the bco.
Each SCS pump is poWorod from vne of the two 4.16 KV vital buses. Each of the 4.16 KV vital busos normally receives power via the 4.16 KV permanent non-safoty buses from a station transformer (offsite power) . Upon loss of offsito power, each bus can be poworod from its respective omorgoney diosol generator, or nither bus can be poworod from the alternato AC sourco, the gas turbino generator. Thus, no single failure of the power supplion will result in loss of power on a 4.16 KV vital bus. The System 80+ AC electrical distribution system is described in CESSAR-DC Section 8.3.1. '
A single failure of one of the 4.16 KV vital buses will result in loss of motivo power for une of the two SCS pumps.
However, the plant can still be brought to cold shutdown using the same proceduro and the other SCS train. '
The valvos in a given SCS train are poworod by one or more 480 volt AC motor control conters (MCCs), which are powered by the sano 4.16 KV vital bus that supplies power to the SCS pump in that train. (Note: A given valve receives power from one and only one 480 volt AC MCC.) Pailure of the 4.16 KV vital bus will result in loss of motivo power to all motor-operated valvos in a given train and they will fall "as-is". This failure also results in a loss of power to the SCS pump in the same train. Failure of a single 480 volt AC MCC will result in loss of power to onn or more valves, depending on the MCC, and they will fail "as-is".
If the valves were closed, they will not be able to bo opened. Under this condition, shutdown cooling can not bo initiated using the affected train. However, shutdown cooling could still be accomplished using the other SCS train. Thus, a single electrical failure of a 480 volt AC MCC would not prevent the SCS from achieving its intended
function. If the motor-operated SCS valves wore open at the time of tho MCC failure, the valves could not be closed from the main control room. However, manual valvos in the auction and dischargo piping outsido containment could be closed by handwhool if required.
Each SCS train also receives control and vital instrumentation power from the two 125 volt DC vital busos asapelated with the vital 4.16 KV bus that providos motivo power for the SCS pump and valvos in the train. One of the two SCS suction isolation valvos insido containmont for each train also receives motivo power from a 125 volt DC vital bus VAa a dedicated inverter. A single electrical failuro in the 125 volt DC power supply system would affect only one SC8 train, Failure of a 125 volt DC bus could result in loss of power for the suction valvo insido containment which is powered via an inverter from the DC bus. If the valvo was closed at the time, shutdown cooling could not be established using the affected train. If shutdown cooling was in progress, the affected valve would fail "as-is".
This would not immediately affect shutdown cooling operations, but would result in the loss of one of the redundant means to isolato the affected SCS lino insido containment.
The power breaker for the SCS pump for a given train has two redundant trip coils. Each trip coil receives 325 volt DC control power from separate 125 volt DC vital bus, i.e., the SCS pump 1 breaker trip coils receive power from 125 VDC buses A and I, and the SCS pump 2 breaker trip coils receivo power from 125 VDC buses B and II. Thus, a single failure 4 of a 125 volt DC vital bus would not affect the SCS pump. .
However, failure of the paup's power-breaker would result in t
loss of the pump, lLoss of a singlo 125 volt Dr vital bus woula also load to loss of some of the instrumentation used to monitor and control the shutdown cooling process. If this woro to happen, the operators could continue the shutdown cooling process with the same procedure using only the unaffected train.
Each SCS suction isolation valvo control circuit includou an interlock that provents opening the valve if the RCS .
prosaure is above a preset limit, prior to-the initiation of shutdown cooling, a single failure of a valvo interlock would result in the inability to open the valvo. Shutdown cooling could still be accomplished from the control room using the unaffected SCS train. Should the single failure occur while shutdown cooling was in progress, there would be no immediate impact as the interlock is a permissive signal only.
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Qugation 440.57 Regarding the pcwer supplies to the SCS isolation valves, confirm that a single failure of a power supply will not prevent isolation of the BCS when RCS pressure m tcoods the design pressure of the SCS. Also, a single fa e in power supplies cannot result in the indbility to initiueo at least one train of the SCS. Confirm thtt the autoclosure interlock for the SCS isolation valves have been removed for System 80+.
gesponse 449152 As shown in Figure 6.3.2-1C, the low-prossure portion of SCS suction line piping is normally isolated from the RCS by two motor-operated isolation valves in series (SI-651 and 653 in shutdown cooling line 1, SI-652 and 654 in shutdown cooling line 2). SI-651, 652, 653, and 654 and the piping in which they are installed are designed to RCS design pressure.
Each of the four valvos is poworod by a separato emergency power supply: SI-651 from train A, SI-653 from train C, SI-652 from train D, and SI-654 from train D. Trains A and C are supplied from electrical division I, and trains D and D are supplied from electrical division II, as described in CESSAR-DC Section 8.3. This arrangement ensures that the operator can isolate both SCS suction lines from the RCS from the main control room in the ovent of a single power supply failure.
In the SCS dischargo lines, the low-pressure portion of the SCS is isolated from the RCS by four check valves and ono motor-operated isolation valvo (SI-601 in shutdown cooling line 1, SI-600 in shutdown cooling line 2). SI-600 and 601 are powered-from electrical trains consistent with the auction isolation valves, i.e., SI-601 is powered from train A, which is supplied from electrical divielen I, and SI-600 is powered from train D, which are supplied from electrical division II. Therefore, in the event of a single power supply failure, at least one SCS train can be aligned for operation from the main control room.
The response to Question 440.53 includes additional information en tho offect of electrical single failurcs on the Shutdown Cooling Syster.
The_autoclosure interlock for the SCS isolation valves is not used in the System 80+ design.
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Onta119A___14Ada Discuss provisions of pump protection available for SCS pumps from potential low flow or no flow operating conditions.
RieP9nte..liAdt The design of the System 80+ Shutdown Cooling System (SCS) has clininated the potential for pump low ficw or no flow operation without the occurrence of multiple failures. Chapter 5, Section 5.4.7 of CESSAR-DC defines the functional design bases for the SCS such that the pumps are required to operate in support of the following conditions:
a) shutdown cooling, b) transfer of coolant to the CVCS for purification during the shutdown cooling mode, c) transfer of coolant from the fuel pool back to the IRWST following refueling operations, d) backup to the containment Spray System (CSS) for IRWST heat removal during accident conditions.
Most notable is the deletion of the low pressure safety injection function on receipt of a Safety Injection Action Signal. The result la that the SCS pumps now operate in a closed loop environment where the pump's head is only a function of the line losses. The static pressure in the RCS will not change the pump's head as in an open loop system, where the operating point is determined by the system back pressure. Therefore, from the functional bases requirements, none of the design modes will require the pumps to be operated in a low flow, no flow condition.
As described in CESSAR-DC Section 5.4.7.2.2.E, each off the SCS pumps la provided with a minimum flow (miniflow) recirculation line to provide pump protection. The miniflow lines are routed from the pump discharge back to the pump suction; seo CESSAR-DC Figures 6.3.2-1A and 6.3.2-1B. The miniflow lines have no remotely actuated valves; a locally operated manual valve that is provided in each line to allow pump maintenance is locked open during all plant operating modes. A heat exchanger is provided in each miniflow line to remove pump heat in the event of a closed pump discharge path due to operator error.
Each of the SCS pumps is provided with a low shutdown cooling flew alarm. The alarm setpoint is established based on the flow rate required for shutdown cooling operations. An alarm will alert the operator to low flow conditions that may lead to-a loss of shutdown cooling due to either a loss of adequate pump suction or the closure of a system valve. Instrumentation that would alert the operator to a low flow condition due to closure of the SCS nuction line isolation valves is discussed in the response to NRC question 440.54.
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The System 80+ design provides four high prosauro safety i injection pumps. Discuss the pupp performance following a i safety injection signal due to a large break I/JCA. What i provisions are available to provent thoso HPSI pumps from i runout due to low RCS pressure? i ResDonse 440 Jz2 [
I Maximum SI pump flow is limited to an acceptable runout !
value when the system is set up during pre-operational I testing with the RCS at atmospheric pressure. In the event !
of a large break LOCA, maximum SI pump flow will not excond ,
the maximum flow rato established during pro-operational i testing, even at low RCS pressures. SI pump performance -
following a largo break LOCA is discussed in CESSAR-DC ,
Section 6.3.2.2.3 and overall SIS performanco is discussed I in CESSAR-DC Section 6.3.3.
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r Question 440.6},1 !
Provide the calculated available NPSH values for the llPSI pureps during '
injection mode and lon6 term cooling mode and demonstrate that sufficient I margins exist under various operating conditions, L Response 440.6),1 ,
The Safety injection pumps for System 80+ take suction from the in.contairmnt ,
Refueling Water Storage Tank (IRWST). Because this tank serves as the suction
- a source for both injection and recirculation, there is no distinction between these modes of operation, e
The available not positive suction head (NPSHA) was determined using the ,
following equation:
i NPSHA a H a
+H sa HfHvp i i
Wheret H, is the pressure (in feet of fluid) that vaists at the free 4
surface of the suction source (IRWST),
H,, is the elevation head from the pump suction to the surface of the suction source.
Hg is the head loss due to fluid flow.
II is the vapor pressure (in feet of fluid) of the fluid at the pump suction, Since the expected pumped fluid temperature may exceed 212'F. the NPSH for the SI pumps was calculated assuming that-the temperature of the pumped liquid is-at saturation for the containment pressure, and that the vapor pressure is equal to the containment pressure. These assumptions ensure that no credit is taken for containment pressure since the containment and vapor pressure terms cancel out of the NPSH equation. Moreover, these assumptions agree with the '
intent of Regulatory Guide 1,1.
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The NPSHA equation then reduces to:
4 NPSHA - H,, Hg The maximum expected flow rate for each SIS pump will result in the miniaam NPSHA. Therefore, a runout flow of 1235 gpm/ pump was used in this calculation.
Elevations and piping runs were estimated conservatively f rom Plant General Arrangement Drawings and Piping Layout Drawings.
The calculated value for NPSHA for the safety injection pumps is approximately 27 feet. This includes both Safety Injection and Containment Spray pumps taking suction from the IRWST at runout flows.
The SI pumps for System 80+ are being specified to the same operating and performance requirements as those that were used for the System 80 High Pressure Safety Injection (HPSI) pumps. The required NPSH (NPSHR) for the System 80 HPSI pumps was 20 feet, or less, at pump runout flow. Based on the similarity of the operating and performance requirements of the System 80+ S1 i
pumps to.those of the System 80 HPSI pumps, NPSHR for the System.80+ SI pumps is expected to be the same; _thiswillbef!IIirmedwhenSystem80+S1 pump procurement efforts are initiated. Comparing the NPSHA of 27 feet at pump runout flow to the NPSHR of 20 feet, it has been determined that the margin between the NPSHA and tho NPSHR is sufficient for all modes of System 804 SI pump cperation.
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Rusronse 440.65 (continued)
From g2rI 6.3.3.3-1 of CESSAR-DC, the minimum SI pump flow rate to the reactor vessel at an RCS pressure of 20 psig is 9 76 --46tr gpm por pump, or approximately 130 lbm/sec por pump.
Therefore, the two SI pumps available following a diesel generator failure will provide a total injection flow rate of 260 lbm/see to the reactor vessel. That is 50 lbm/sec or approximately 254 greater than the 210 lbm/sec that is calculated to be reflooding the core (i.e., leaving the downcomer/ lower plenum) immediately after the SITS empty for the limiting LBLoCA.
Therefore, SI flow from only two SI pumps will indeed keep the downcomer filled to the elevation of the pump discharge leg in the same time frame as with all four SI pumps feeding the reactor vessel.
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I ouestion 440.66 7dontify any longths of ECCS piping which have normally closed valvos that do not have pressure relief in the piping section between the isolation valves. Vorify that all pressure isolation check valvos can bo individually tasted for back leakago.
RecDonne 440.66 All lengths of ECCS piping with normally closed valven have pressure reliefs in the piping acetion between the isolation valves.
The pressure isolation chock valvo ncarest the RCS in each of the four safety _ injection lines (valvos SI-217, 227, 237, 247 on CESSAR-DC Figuro 6.3.2-1C) can bo individually testod for back leakage. The pressure isolation check valvo second from the RCS in cach of the four safety injection tank linos (valves SI-215, 225, e35,-245 on CESSAR-DC Figure 6.3.2-1C) can be tested for back leakage in conjunction with the first pressure isolation check valvo. The pressure isolation check valvo second from the RCS in each of the four safety injection pump lines (valves SI-540, 541, 542, 543 on CESSAR-DC Figuro 6.3.2-1C) can be tested for back leakago in conjunction with the first check valves and other check valvos upstream.
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Qunstion 440.67 Provide a list of all active components which are required for oporation of the ECCS. Provide safety and soismic classification for each component and indicate what services such as cooling, lube oil, and air are necessary for the proper functioning of each component.
t Ensponse 440.67 The following active components are ruquired for operation of the safety injection, shutde. .;ooling, and containment spray systems, which are descriu;2 in CESSAR-DC, Amendment I, Sections 5.4.7 and 6.3. Services required for the propor functioning of each component are also listed. Safety and seismic classification for each component is presented in Table 3.2-1 (for pumps) and Table 3.2-2 (for valves).
.CDRR0atat Eerviceg Safety Injection Pumps Component Cooling Water Elcetrical Power Shutdown Cooling Pumps component cooling Water Electrical Power Containment Spray Pumps Component Cooling
- Water Electrical Power SI-100, 101 (IRWST Return Check) Nono SI-113, 123, 133, 143 (SI Containment Hono Check SI-157, 158-(Containment Spray Check) None SI-164, 165 (Containment Spray Check) None SI-168, 178 (SCS Check) None SI-179, 189 (SCS Suction Line Relief) None SI-215, 225, 235, 245 (SIT Check Hone Valve)
SI-217, 227, 237, 247 (Safety Nono Injection Chock)
SI-300, 301 (CS/SCS IRWST Recirc Line Electrical Power Isol.)
SI-302, 303 (SI-IRWST Recirc Line Electrical Power Isol.)
SI-304, 305, 308, 309 (IRWST Isol.) Electrical Power SI-310, 311 (SDCHX Flow Control) Electrical Power SI-312, 313 (SDCHX Bypnos Flow Electrical Power-Control)
SI-314, 315 (SCS IRWST Recirc Flow Electrical Power Control)
SI-321, 331 (Hot Leg Injection Isol.) Electrical Power
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SI-322, 332 (llow Lcq Check Valve Lesk Air, DC Power Isol.)
SI-390, 391, 392, 393 (Holdup Vol. Electrical Power Tank Spillway)
SI-394, 395 (Reactor Cavity Spillway) Electrical Power SI-404, 405, 434, 446 (SI Pump Hone Discharge Check)
SI-424, 426, 448, 451 (SI Pump Bypass None Check)
SI-484, 485 (CS Pump Discharge Check) None SI-522, 532 (SI Ilot Leg Injection None check)
SI-523, 533 (SI Hot Leg Containment None Check)
SI-568, 569 (SCS Pump Outlet Check) None SI-600, 601 (SCS Train Isolation) Electrical Power SI-602, 603 (SI Low Flow Control) Electrical Power SI-604, 609 (SI Hot Leg Injection Electrical Power Isol.)-
SI-605, 606, 607, 608 (SIT Atmospheric Air, DC Power Vent Isol)
SI-611, 621, 631, 641 (SIT Fill & Air, DC Power Drain Isol.)
SI-613, 623, 633, 643 (SIT Atmospheric Air, DC Power Vent Isol)
SI-614, 624, 634, 644 (SIT Discharge Electrical Power Isol.)
SI-616, 626, 636, 646 (Injection Line Electrical Power Isol.)
SI-618, 628, 638, 648 (Check Valve Air, DC Power Leak Isol.) _
SI-651, 652,.653, 654 (SCS Suction Electrical Power
- Line Isol.)
SI-655, 656 (SCS Suction-Line Isol.) Electrical Power SI-657, 658 (CSS IRWST Recirc Flow Electrical Power Control)
SI-661 (RDT Isolation) Air, DC Power SI-670 (IRWST Return Isolation) Air, DC Power SI-671, 672 (Containment Spray Header Electrical Power Isol.)
SI-682 (SIT Fill Line Isol.) .
Air,_DC Power SI-680, 696 (CS HX to IRWST Isol.) Electrical Power SI-687,.695 (CS Header Block) Electrical Power
- SI-688, 693 (SCS IRWST Recirc Isol.) Electrical Power
- SI-690, 691 (SCS Train Warm-up Flow Electrical Power Control) y ,- --vv , -, - , , -
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Question 440.70 Describe the means provided for WCCS pump protection including instrumentation and a32?.rms available to indicato degradation of ECCS pump perforntence. The staff's position is that suitable means should be provided to alert the operator promptly to possible 0+grodation of ECCS pump performance. All instrumentation associated with monitoring the ECCS pump performance should to Operable without of fsite power, and should be able to detect conditions of low discharge flow.
Resoonse 440.7Q The following instrumentation is used ta determine Safety Injection and Shutdown Cooling pump per!crmance. This
<- instrumentation is shown in Figures 6.3.2-1A, D, and C and described in Section 6.3.5.3 of CESSAR-DC.
Channel Function Cpntrol Ro2E Featured P-302, 305 SCS Pump Djscharge Indication Pressure P-306, 307, SI Pump Discharge Pressure Indication 308, 309 P-319, 329, SI Line Pressure Indication 339, 349 Alarm (High)
P-390, 391 SI Hot Leg Injection Indication Pressure Alarm (High)
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F-302, 305 SCS Line Flcw Indication
-Alarm (Low)
F-306, 307, SI Pump Discharge Flow Indication 308, 309 Alarm (Low)
F-311, 321, DVI Nozzle Injection Line Indication 331, 341 Flow F-390, 391 SI Hot Leg Injection Flow Indication The normal power supplies for the above instrumentation are the 120 VAC vital I&C buses, which are powered from either the class 1E 480 VAC buses or the 125 VDC buses through invorters (See CESSAR-DC Figure 8.3.2-2). If offsite power is lost, the_ Class 1E 480 VAC buses may be poworod via the 4.16 KV safety-buses by the emergency diesel generators (See CESSAR-DC Figure 8.3.1-1) or by the alternate AC power source (gas turbine).
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Testing to confirm that SI and SCS pump performance is j within specification is included in the Safety Injection System Test sections of Preoperational Tosts, Section 14.2.12.1- of CESSAR-DC. In addition, Technical Specification 3.5.2 (CESSAR-DC Section 16.8.2) providos requirements for testing safety injection flowrates.
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i 92eJticn.MQ 11 Discuss the percentage of safety injection (SI) flow capacity (in terets ;
of best efficiency flow) for the SI pterp minimum flow recirculation ,
required to protect against hydraulic instability or lapeller !
recirculatfor. problems during extended SI pump low flow operations. l (Reference NRC Bulletin 88 04, May 5, 1988)
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Rtgponse 440.71 l The SI pump characteristics and the Safety injection System have been 3 designed to pruent the hydraulic instability and impeller recirculation '
problems repor"ed in the NRC Bulletin 88 04. In developing the system, the design has addressed the potential sources delineated in the NRC Bulletin and includes the following resolutions:
- 1) Shape of the pump Curve: According to the NRC Bulletin, the primary l cause of hydraulic instability is due to the shape of the typical ;
centrifugal pump curve with low specific speed. Spacifically, system l operation of the pump near dead head conditions yleids performances ,
that flatten out or exhibit a downward concavity, producing a reduction in head with a reduction in flow. This phenomenon is significantly more prevalent with low head, high flow, low specific speed pumps. The System 80+ Saf ety Injection Systeros ptutps are high >
head, low flow, high specific speed pturps whose performance curves do not flatten out as the they approach low flows. Therefore, hydraulic instability is not a concern for.this system design. -
- 2) Train to Train Cross Connection: The arrangement of the Safety injectior. System miniflow recirculation lines precludes pump to puep interaction of the kind discussed in the NRC Bulletin 88 04. The only cross connects provided in the System 80+ SIS arrangement ties two discharge recisculation lines together down stream of an orifice and-a check valve,-and then provides a path.to the vented IRWST.
There is no plausible operating configuration which would cause the operattore of one SI ptuep to cause other Si pumps to operate at a low (Iow rate that is lower.than the minimum flow required for pump -
protection. Therefore, cross cor.nection of trains in the SIS with parallel pump operation is not a concern for hydraulic instability or impeller recirculation. ;
- 3) Design Value for Recirculation Flow: The third concern addressed in the NRC Bulletin 88 04 was the deterisination of the proper itiniflow that should be provided to protect the pump against suction and/or discharge tip recirculation. The NRC has recomaended that a flow rate in the range of 254 to 50% of best efficiency flow abould be used w a guide in establishing the miniflow rate. This range also corresponds to both the pump vendots recommended flow and also correoponds to the defined onset of impeller recirculation as i
, delineated in coitoon pump handbooks. This range, however, does not '
relate to r pecific pturps and applications nor to the point where significant performance degradation would occurs. Therefore, in the interest of optin.1 ring the Safety Injection System design, i.e. ,
limiting the size of the pumps, motors, piping and the operating cost
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! pump vendors and utilities, perforsted an extensive investigation into the specific pump to be used for this application.- The resulta yielded that the minimum flow for the Saf ety injection pumps need not i be as high as recommended, but should be in accordance with {
previously established values of 85 to 105 gpm or 9.7% to 12% of Bti' i efficiency flow. This flow has been shown to protect the pweps from l j dareage associated with operation at low flow for the specific I
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- Qutation 440.75 CESSAR-DC Section 6.3 addressos operator actions for post-LOCA operations. Which valves require manual closure on the injection path for SI-3 and SI-4 during valvo realignment for simultaneous direct vossol injection (DVI) and hot log injection? List all valvos requiring manual operation, administrativo contrvis/ procedures of those valves, and control room featerri (1 e. , key-operated control switches, valvo position indteut ht that minimizo the potential for valve misalignment.
Response 440.75 Hanual actions for faubCOCA long term cooling are presented in CESSAR-DC Socth e 63,2.7, Amendmont 1. All controls and position indication for valves requiring post-LOCA manual l operation are located in the main control room (McR).
Realignment for nimulte.neous direct vessel injection-(DVI) ;
and hot log injection !,ts performed by the operator from the HCR for one safety injnction train at a timo. Tho hot log injection valvoa SI-604 (SI-609) and 81-321 (SI-331) in tho l path from safety injection pump number 3 (4) are opened, and the corresponding'DVI valvo SI-636 (SI-616) is closed.
Valvos SI-646 and SI-026 in the DVI nozzio flow paths of SI pumps 1 and 2 romain open. Hot 109 injection valvon SI-604, 609, 321, and 331 are normally closed valvon which are i administrativo1y controlled in the MCR to provent inadvertent hot log injection. Administrative proceduros ,
prepared by the plant owner will incorporate the guidance of CESSAR-DC, Section 6.3.2.7.
The valvos requirang realignment for simultaneous DVI_and hot log injection are provided with position indicators l Which transmit valve status to the Engineered Safety
- Features Component Control System (ESF-CCS). The ESF-CCS lights the appropriate McR valve status lamps and provides -
input to the Data Processing System.(DPS) for valvo status display on appropriate CRT display pages. The DPS also provides succeso path monitoring (SPM) which determinos
-success path availability and performanco based on valvo lineups,-activo component statum (800 CESSAK-DC Section 18.7.1.8.2), ar$ process parameters. If during tho' valve realignment process a valvo is misaligned a success path unavailability alarm (Priority 2 or 1 depending on impact) is generated. This would be indicated to the operator on the big board IPSO, all DPS CRTs and a DIAS spatially dedicated alarm tile on the safety monitoring panel.
Additionally, the DPS computer aided test (COMAT) program i .
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monitors ESP system plant lineups for correct post-test conditions to ensure proper operation line-ups have been established after any testing is performed (See CESSAR-DC Sections 7.3.1.1.U.6 and 7.7.1.8.2). The EST-CCS provides monitoring and indication of valves which are locally misaligned or become inoperativo due to loss of control or motive power (soo CESSAR-DC Section 18.7.1.6.2.10). These conditiens are also provided to the operator through DPS and Discreto Indication and Alarn System (DIAS) alarms and displays.
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Question 440 83:
A recent licensee event report from an operating reactor indicated that all of its safety injection pumas became inoperable due to freezing of the minimum rqirculationlinestotierefuelingwaterstoragetank(RWST). The System 80 design has minimum recirculation lines from the safety injection pumps (located outside containment) connected to Proviou a descriptionoftheproceduresandSystem80}heincontainmentRWST. design features that would prevent the occurrence of frozen recirculation lines and associated safety injectionlines.
Briponse 440 831 Although the safety injection pumps and associated piping are located outside the containment there are no lines that are exposed to the "outside environment." Unlike current operating plant designs, the System 80+ design incorporates an in containment Refueling Water Storage Tank (IRWST). The Si pumps are located in the Reactor Building, which is climate controlled by the HVAC Systems. Moreover, the Reactor Building surrounds and is directly cor.nected to the containment structure. Therefore, the safety injection minimum flow recirculation lines pass directly into and out of containment without exposure to a frigid external environment. In this way, the water that remains stagnant in the minimum flow rer.irculation piping during normal plant operation will not freeze.
Refer to figures 1.2-3 and 1,2-4 of CESSAR-DC for the Nuclerr Island General Arrangement that snows the relationship of the Reactor Building (and consequently the SI pump room) to the containment structure),
l 44083. DOC
Question 440.86 In CESSAR-DC,-Chapter 15, expand the sequence of event descriptions of the limiting transients and accidents in each event category. Include the following Question 440.86(a)
Identify all components and systems that are called upon in event mitigation that ensure safe shutdown of the plant.
Regnonse 440.86(a)
The following table lists the components and systems credited in the analyses for the mitigation of each event.
The events listed include only the most limiting accident and the most limiting anticipated opocational occurrence, with respect to the applicable acceptance criteria, in each of the seven initiating event categories-given in Section 15.0.1.2 of CESSAR-DC. See also the response to Question 440.86(e).
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1 CESSAR DC Components and Systems Credited for Section No. Limitina Event of Cattggn til1Lgalign_and ShutdowL 15.1.4 Inadvertent Opening of a Manual Reactor Trip.
Steam Generator Atmospheric Steam Generator Low level Signal.
Dump Valve Combined with a low Pressurtzer Pressure Signal.
Single failure Emergency Itedwater System.
Safety injection System.
Atmospheric Steam Dump System and Block Valves.
15.1.5 Steam Line Bra k Outside CPCS Variable Overpower Trip Signal.
Containment inring Full Low Steam Generator Pressure Signal.
, Power Operation with low Pressurizer Pressure Signal.
Offsite Power Available Main Steaei Isolation System.
Safety injection System.
Atmospheric Steam Dump System.
15.2.3 Loss of Condenser Low Reactor Coolant Pump Shaft Speed Vacuum Combined with Reactor Trip Signal.
Loss of Offsite Power low Steam Generator Water Level Signal.
Pressurizer Safety Valves.
M.dn Steam Safety Valves.
Atmospheric Steam Dump System.
Emergency Diesel Generators 15.2.8 feedwater Systems High Pressurizer Pressure Trip Signal.
Pipe Breaks with Loss low Steam Generator Level Signal.
of Offsite Power and Low Steam Generator Pressure Signal.
Failure of One Emergency Pressurizer Safety Valves.
Feedwater Pump Main Steam Safety Valves.
Main Steam Itolt. tion System.
Atmospheric Steam Dump System.
15.3.1 Total Loss of Reactor low Reactor Coolant Pump Shaft Coolant Flow Speed Reactor Trip.
Pressurizer Safety Valves.
Atmospheric Steam Dump System.
15.3.3 Reactor Coolant Pump low Reactor Coolant Flow Reactor Trip.
Rotor Seizure with Loss low Steam Generator Level Signal.
of Offsite Power Main Steam Safety Valves.
Main Steam Isolation System.
Pressurizer Safety Valves.
Atmospheric Steam Dump System and Block Valves.
CESSAR DC Components and Systems Credited for SK1101Lho o Ltqitina Eyrn_1 of Diggary Hitlgation_3nd_itiq1down _,
15.4.3 Single Control Element Reactor Protection System.
Assemoly Drop 15.4.4 Startup of an inactive Reactor Protection System.
Reactor Coolant Pump Pressurizer Safety Valves.
Math Steam Safety Valves.
Shutdown Cooling System Safety Valves.
15.4.6 Inadvertent Deboration liigh Pressurizer Pressure Reactor Trip.
High Logarithmic Power Level Reactor Trip.
Operator Control of chemical and Volume Control System.
Boron Dilution Alarm.
15.4.8 Control Element Assembly low Steam Generator level Signal.
Ejection with Loss of Variable Overpower Reactor Trip.
Offsite Power Pressurizer Safety Valves.
Main Steam Safety Valves Emergency feedwater System.
Atmospheric Steam Dump System.
Containment Purge Isolation Valves.
Containment Building.
Containment Annulus Ventilation System.
Containment Spray System.
Subsphere Building Ventilation System.
15.5.1 Inadvertent Operation Shutdown Cooling System Relief Valves.
of the ECCS 15.5.2 CVCS Malfunction - High Pressurizer Pressure Reactor Trip.
Pressurizer Level Control Pressurizer Safety Valves.
System Halfunction Main Steam Safety Valves.
Atmospheric Steam Dump System.
15.6.5 Loss of Coolant Containment Purge Isolation Valves.
Accident (Dose) Containment Building.
Containment Annulus Ventilation System.
Containment Spray System.
Subsphere Building Ventilation System.
15.7.3 Postulated Radioactive No Active Systems or Components Releases Due to Liquid- Mitigate the Occurrence of this Event.
Conthining Tank failures 15.7.4 fuel Handling Accident Containment liigh Volume Purge Ventilation System, luel Building Ventilation Exhaust System.
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QUESTION 4tE406fb) j In CESSAR-DC, Chapter 15, expand the soquence of event descriptions ,
i of the limiting transients and accidents in each event category.
Include the following List non-safety grado components and systems that are called {
upon in the scenario of ovent mitigation por emorgency operating proceduros (EOPs) developed from the CE Emorgency "
Procedure Guidelinos (EPGs) .
Rnpsate- 449.2.811.k1 The Emergency Procedure Guidelines are developed using best estimato analysis tools and assumptions and as such may employ non-safety grado equipment (if available) for event mitigation.
With the exception of the event listed boisw, no non-safoty grado grado componaats and systems are calltid upon to ritigato the consequencos of tho events in Chapter 15. Non-safety grado components and systems are considered in the anelycos in such a way as to make the consequences of the design basis ovents more adverse than those realized without the performance of such !
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compenents and systems. This approach results in a conservative evaluation of Chaptor 15 events. The exception is the credit for multiple non-safety grado alarms following a letdown line break. The use of tho non-safety grado alarms to alert the operator following a letdown line break is discussed in RAI 440.104.
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In CESSAR-DC, Chaptor 15, expand the sequence of event descriptions of the limiting transients and accidents in each -
event category, include the followingi Provido an assoasmant of the most limiting consequences of each ovent analyzed in CESSAR-DC in light of an actual event scenario using EOPs with f ailures of non-safety grado mitigating equipment that result in a timo deley of in.itiation of safety grade mitigating components and systems.
BERQNSE 440 Ji_191 For most of the CESSAR-DC Chapter 15 events, the most limiting consequences occur prior to when operator actions would be expected to occur. For examplo, the peak RCS pressure for a Foodwater Line Break occurs within the first 40 seconds after the initiation of the break. Likewise, for a double-ended steam line break, adverso impact on fuel performance occurs during the first few seconds (less than 10 seconds) of the transient during which safety grado equipment is relied upon to obtain acceptable event consequences. Only in the caso of an event which could result in releano of radioactivity does impact of operator actions become significant. For this reason, the most limiting ,
steam generator tube rupture (SGTR) event was analyzod in CESSAR-DC in light of the CE Emergency Proceduro Guidelines (EPGs). The ovent analyzed was a SGTR with a loss of offsito power (LOOP) and a stuck open steam generator atmospheric dump valvo (ADV) as a single failure. The analysis of this event scenario which simulated the guidelines of the EPGs demonstrated that the radiological reloanos woro well within the 10 CFR 100 limits and that the operator was able te control the affected SG water level so as to provent overfilling.
Time delays for automatic actuation of safety-grado mitigating components and systems woro included in the Chapter 15 ovent analysos rogardless of whethcr the delays were as a result of f ailures of non-safety grado equipment or not. In fact, no manual operator actions to initiato safety-grado equipment have been assumed for the first 30 minutes of any event. It is expected that any postulated timo delays due to use of non-safety grado equipment-first and then safety grado equipment (assuming non-safety grado equipment malfunctions after-actuation) would not exceed this 30 minuto allowance and would not adv.tsely impact the event consequences, sinco (1) automatic actions would provido adequate protection early in the transient, and (2) the operator will act in a manner to counteract any system failures quickly since he would bo in control of the plant-at the time of the failure.
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l Question 440.91 In your analyses of all four SLB cases (case i through case 4) chosen to maximize the potential for a post-trip return to power, you have stated that since there is no return to power, the valuer, of DNBR tennin above those for which fuel damage would brs indicated. The staff does not consider that the fact ci' no return to power would necessarily result in tha values of DNBR remain above the minimum DNBR. The transient DNBR could be affected by rapid depressurization of RCS and loss of forced circulation following the assumed loss of offsite power.
Discuss tha above staff concerns and provide transient DNBR curvra for all SLB cases.
Rtgponte 440.97 The SLB events are analyzed in two ways. The first set of
.nalyces maximize post-trip degradation in DNBR. The second set maximizes pre-trip degradation in DNBR. For the first set (SLB cases 1-4), the initial conditions are adjusted to maxinize the post-trip degradation in fuel performance (i.e., near the time of maximum reactivity, which occurs several minutes after reactor trip). For these cases, there is no post-trip return to power and as a result, the DNDR during this time interval of maxinum reactivity does not approach the DNBR limit. Howeve't, thero is a potential for violating the transient DNF,R limit during the pretrip time period. However,'.he second set of SLB analyses yield worse results since the initial cenditions are adjusted to maximize the event consequences at that time The second set of analyses are the pre-trip cr.ses. These are specifically analyzed to maximize the rLcential for fuel damage near the time of reactor trip. The results of ,
these limiting DNBR cases are provided in CESSAR-DC section 15.1.5.
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l is initially at the low steam generator level trip. If the feedwater control system is in the automatic mode, the plant would be at the normal water level, consequently, with a larger steam generator inventory, the rate of steam generator depressurization, and RCS cooldown rates would be decreased, resulting in a slower increase in core power and hence higher minimum DNBRs.
High energy line break interactive failurer in the steam bypass control system do not impact steam line break cases prior to the nain stnam isolation valve closure on low steau generator pressure as the flow exiting both steam generators is choked at both nozzles. The only case where the potential for more adverse results exists, for a steam bypass system failure is in the post trip return to power cases with ac power available and a failure in the intact steam generator MSIV. An additional feilure in the steam bypass control system was not considered credible as the probability of a steam line break with the most reactive rod stuck out, and the failure of e main steam isolation valve to close (which because of the design of their actuators, requires two separate failures) is exceedingly low, t
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OUESTION 440.100 ,
-l NRC IE Information Notice No. 79-22 identified concerns ;
for several non-safety grade control systems including (1) j steam generator PORV (ADV for System 80+) control system, (2)' pressurizer PORV (SDS for System 80+) control system, (3) main feedwater control system, and (4) automatic rod control system. These systems may not be properly qualified for adverse environment conditions, and they could potentially malfunction due to the adverse environment caused by a high energy line break inside or outside of containment. Assess the consequences of the failure of the similar control systems in conjunction with each of the SLB case analyzed in CESSAR-DC Section 15.1.5.
RESPONSE 440.10A of the control systems mentioned in the question the steam generator ADVs upstream of the main steam isolation valves and the safety Deprensurization System valves are manually operated and are in safety grade systems and therefore are not subject to the failures discussed in IE Information Notice number 79-22.
For the pre-trip steam line break cases, the reactor regulating system is. assumed to be in the automatic mode thus pulling rods at the maximum rate until the time of reactor trip, and the existing analysee bound the potential for a high energy line break interaction L impacting the reactor regulcting. system. The post trip return to power cases are not impacted by the reactor regulating system failure, as all rods are inserted (except for-the most reactive rod) at the time of maximum post trip reactivity.
L For the steam line break cases with the loss of ac power, the steam bypass and feedwater control systems are not available iue to the lack of available power. As a result, t;.a only steam line break cases impacted by a high energy line break interaction in these two control systems are those with a-c power available.
The post trip return to power steam line break cases assume the main feedwater system to be in the manual mode with the level at the high steam generator level trip setpoint. If +5e main feedwater system were in the automatic modt. the steam generator level would lua at its
- normal water level. With the resulting lower steam generator inventories the plant cooldown and maximum post trip reactivity would be reduced.
The feedwater control system is also in the manual mode for the pre-trip steam case as the steam generator level
Question 440.101 CESSAR-DC Table 15.6.2-2 ,- .cated that the non-safety grade pressuriecr hooters c.re assumed to function in accident mitigation. Provide the results of a reanalysis of the letdown line break accident assuming only safety-grade alarms, components, or systems available for accident mitigation.
Resoonse 440.104 Consistent with the discussion in Section 15.0.2 on the bases for Chapter 15 analyses, normal automatic operation of the pressurizer pressure and level control systems "is assumed unless lack of operation would make the consequences of the event more severe." For analysis of this event the assumption of heater operation is appropriate because the heaters tend to maintain higher primary pressure following the letdown line break. Higher primary pressure maximizes the break flow rute and consequently also the calculated dose. A reanalysis without the heaters would therefore show less adverse results. The analysis as presented assumes that only safety grade components and systems are employed for the active mitigation of the event.
The radiological consequences presented in CESSAR-DC,
-Section 15.6.2, are derived from analyses that credit one out of seven available, non-safety grade alarms. The multiplicity ot alarms provides confidence that at least one alarm will occur to alert the operator to an event.
The limiting critorion for the letdown line break is the radiological dose, which is directly related to the quantity of primary coolant released, and the quantity released depends on the timing of the earliest alarm. As discussed in Section 15.6.2, all seven alarmed parameters reach their alarm setpoint within a few minutes, whereas the analysis assumes operator action is delayed until 30 minutes after the earliest alarm. Regardless of which alarm is credited, the accident consequences are approximately the same and well below the acceptance criteria of the Standard Review Plan.
There are three distinctly separate groups of alarne contributing to the assurance that an alarm from one group will function. The first group is the pressurizer low level alarm, which is derived from two redundant instrument channels. These channels are part of the Safety Related Plant Processing Display Information (See CESSAR-DC, Table 7.5-1). They are also part of the Post Accident Monitoring Instrumentat. ion (See CESSAR-DC, Table 7.5-3) and satisfy Regulatory Guide 1.97 for Category 1 instrumentation that is Class 1E up to the isolation devices and is displayed on the seismically qualified
Discrete Indication and Alarm System.
The second group of alarms are those in the Chemical and Volume control System (CVCS). They include high temperature at the exit of the regenerative heat exchanger (inside containment), low pressure in the letdown line and dual channels for low level in the volume control tank.
While the CVCS is considered non-safety-related, it is designed as a Safety Class 2 system and is relied on to provide ossential functions for normal day-to-day operation.
The third group of alarms are building and environmental alarms in the auxiliary building. They include building high radiation, high temperature, high humidity and high sump level. The combination of this blanket of environmental building alarms plus the analysis assumption for worst break location helps assure that an alarm vill occur and that the consequences will not be substantJally worse for any location of letdown line break.
In conclusion, the multiplicity of alarms and their diversity Tssure that the analyses presented for the postulated letdown line break provide a valid representation of the radiological consequences.
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QUESTION 440.106 .
CESSAR-DC Section 15.6.3 presents the results of analyses for three cases of postulated steam generator tube rupture (SGTR) event. However, the staff noted that these analyses were performed with non-conservative assumptions such as the use of non safety grade equipment (e.g., pressurizer heaters) for accident mitigation, the use of time delay on loss of offsite power during the event, and assumption of operator action in less than ten minutes, etc. Provide the results of a reanalyris of postulated SGTR event including the following elements for a bounding case.
(1) Assumptioni (a) A double-ended tube rupture at the location which results in the worst radiological consequences.
(b) A loss of offsite power occurred coincident with a reactor trip / turbine trip following the event initiation.
(c) A single failure of an atmospheric steam dump valve (ADV) associated with the affected steam generator.
(d) The failed ADV sticks open at its fully open position. -
(e) A maximum technical specification tube leakage in the unaffected steam generator (1 gpm) allowed by technical specifications.
(f) A maximum technical specification activity level in the primary coolant allowed by technical specifications.
(g) A maximum percentage of steam generator tubes plugged for both S/Gs allowed by technical specifications.
(h) Fuel failure for any fuel pin with tiDNBR below 1.24 as a result of this event.
(i) A minimum of ten minutes operator action time to perform a simple action inside the control room after a clear guidance is available to the operator.
(j) A sensitivity study should be performed for the timing of operator actions to open ADVs following a SGTR. An early opening of ADVs may not be conservative with respect to the radiological consequences since a late opening of ADVs could delay the primary system depressurization and thus prolong the tube leak flow through the ruptured steam generator tube.
(k) Factor in the steps necessary to prevent the steam generator overfill during the event.
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(1)(Only' the safety-grade components and systems are credited in the accident mitigation. All the non-safety grade equipment are assumed to fail when they are called upon to function per the emergency operating
- procedure. 'In the sequence-of events, a time delay of the initiation !
. of-safety grade mitigation' system should be conservatively. assumed to consider the~ time spent _in attempting the use of ncn-safety grade equipment by operating ~ procedures. ' i (2) Information Needed to Present the Results of the SGTR Analysis (a) Sequence of events on a time scale from the initiation of )
L the tube rupture to the shutdown entry conditions.
(b) Operator action times including identification of the faulted SG, isolation of the faulted SG, initiation of cooldown,'depressurization, etc. This should also-be presented on a time scale, ,
(c) Discuss ~ the issue of a potential steam generator overfill,- including-the integrity of the-steam lines under c water filled ccndition and, if applicable, the effects of liquid flow through the ADV or safety valves, si.nce these were not designed for-these service conditions.
In assessing steam generator overfill,-a most limiting single failure =should be considered such as the auxiliary
.feedwater. control' valve. fully open, an- ADV associated with the affected steam generator closed,-etc. Also the effects of continuously-feeding the ruptured steam generator in System 80+
design should be addressed.
(d)' Major transient curves including RCS pressure, secondary water. level, leak rctes for the affected and intact steam
' generators, RCS . temperature, pressurizer volume, total steam flow, _feedwater flow rate, etc.
(e) : Amount of fuel failure based on DNBR.
(f) Calculated radiological ~ consequences as compared to the limit-set-fcrth in 10 CFR part 100 (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />),
including pre-accident and coincident iodine spiking and noble gas inventory based-on technical specification limits.
- (g): Radiological- parameters and curves including mass- flow
-loss with respect to time, flashed fractions, and
-partition and decontamination factors in accordance with
.SRP Section 15.6.3.
(h)- Discussion of the consequences of a postulated tube rupture at the top of the tube bundle, as it has occurred at'the North Anna plant.
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i RESPONSE 440.106:
I (a) All of the SGTR analyses present in CESSAR-DC, Section 15.6.3 I consider a_ double-ended tube rupture a he location which results in the ,
worst radiological consequences.
1- (b)- The analyses of CESSAR-DC Sections 15.6.3.2 and 15.6.3.3 assume a loss of offsite power (LOOP)-3 seconds after the turbine trip. This delay is based on a conservative evaluation of the stability of the weakest domestic electrical grids. A substantiktion of this assumption is provided as response to RAl 440.85.
r 1 (c) The analysis presented in Section 15.6.3 3 includes the single f ailure of steam generator ADV during a SGTR in combination with a LOOP.
, I (d) . The failed ADV included in tne Section 15.6.3.3 analysis is assumed L to be open about 12% to achieve the tech spec limited cooldown rate of 100 degree F-per hour. Since this cooldown rate is tech spec controlled, it would take,an operator error, which is classified as a failure, to result in
+he full opening of the ADV. Thus inclusion'of n stuck ADV plus an operator error to caese it to open to 100% is equivalent to considering multiple failures. Hence the analysis presented in Section 15.6.3.3 com.ider only' ,
the limiting single failure of a stuck ADV which is assumed to have been '
partially open (about 120 for achieving the tech spec controlled conldown - i rate of 100 degree F.
1 (e) : A maximum tech spec tube leakage of I gpm for the unaffected SG is assumed in the analyses presented in Sections 15.6.3.1, 15.6.3.2, and 15.6.3.3. ,
1 (f) The maximum tech spec specific activity is assumed for the primary coolant in the analyses presented in Sections 15.6.3.1, 15.6.3.2, and 15.6.3.3.
1 (g) The maximum percentage of steam generator tubes allowed by the tech-spec was assumed to have been plugged for the analyses presented in Sections >
15.6.3.1, 15.6.3.2, 15.6.3.3.
1 (h) For all SGTR scenarios analyzed in Section 15.6.3, the MONBR remains above 1-24, .
1 (i) An operator action time of about 5 minutes plus-2 minutes- for discrete actions to be completed has been assumed in the analyses. The guidance for this operator action time is_ based on ANSI /ANS-58.8-1984,
" Time response criteria for nuclear safety related operator actions".
-1 (j) A sensitivity study was performed to quantify the impact of varying the timing of operator actions. Early,. intermediate, and late operator actions tied to the timing of reactor trip were considered and the most limiting cases were presented in CESSAR-DC.
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4 4 RESPONSE 440.106 (Continued) 1 (k) The analysis presented in Section 15.6.3.3 includes operator actions per the EPGs to control and prevent overfilling of the affected SG. These actions include, opening of the ADV of the affected SG, termination of emergency feedwater flow to the affected SG, throttling of safety injection flow, and use of the pressurizer gas vent system.
I (1) As iridicated in the response to Q. 440.86 (b), the analyses presented in Section 15.6.3 assume the use of only safety grade equipment for mitigat-ing adverse event consequences. It is indicated in the response to RAI 440.86(c) that the time delays due to use of non-safety grade equipment first and safety grade equipment later would not lead to more adverse consequences, since automatic actions by safety grade equipment would provide >dequate protection early in the transient, and the operator would be in a position to quickly counteract any non safety system failures.
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QJ1ES_TlQN 440.108 Discuss the radiological consequences for a small rupture in a
- steam generator if the event does not result in actuation of i the reactor protection system and safety grade alarms to alert the operators.
REFSPONSE 440.108:
The radiological consequences of small tube rupture without the
. intervention of the reactor protection system and/or the operators would be well within the limits of 10 CFR 100, since the steam from the affected steam generator (SGs) flows through the turbine end condenses in the condenser and is cycled back as feedwato to the SGs. The major release point for
- radioactiv; <jases would be the condenser air-ejectors for which a decontamination factor of 100 would be applicable. Along with this factor, a partition factor of 100 would be applicable in the affected SGs. Thus the steam releases at the condenser air-ejector would be divided by a factor of 10,000 to obtain the radiological releases, resulting in significantly small doses.
Note that this scenario cannot continue indefinitely, since sooner or later the condenser hot well level will increase, causing intervention by the operator.
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Duestion 440-113:
Review of CESSAR-DC Chapter 16, Technical Specifications for the System 80+
design indicates a discrepancy between Surveillance Requirement (SR) 3.5.1.4 (page 16.8 2) and section 6.3 on the boron concentration for the Safety injection Tanks (SITS). Section 6.3 states that the SIT boron concentration for the safety analysis is between 4000 ppm and 4400 ppm. The Technical Specifications cite the SR on SIT boron concentration between 2000 ppm and 4400 pcm. SR 3.5.1.4 should be corrected to reflect the boron concentration assumptic made for the ECCS safety a- " sis tri Section 6.3.
Response 440-113:
The number that appears in section L '
rom)isnotthenumber used in the ECCS safety analysis. Th. 4 ; tion of boron used in the safety analysis is 2000 ppm, which it - ' appcars in Surveillance Requirement 3.5.1.4 of Chapter . of Cl.4: ' -DC.
-The number that appears in the text of section 6.3.2 (2.5% weight percent boric acid) represents a maximum concentration that is not to be exceeded in order to prevent boron precipitation. This weight percent corresponds to a boric acid concentration of 4400 ppm. This upper bound appears in the Technical Specifications -in Chapter 16 as well.
The attached sheets from section 6.3.2 of CESSAR-DC show the revisions-that will appear in the next amendment to CESSAR-DC to help clarify this issue.
QUEETION 440.111 -
Provide a description of the Safety Depressurization System initiation procedures to be used by System 80+
operators during a feed and bleed heat removal process.
Provide a schedule for submission of System 80+ Emergency Procedures Guidelines (EPGs).
BES20NSE 440.114 The design basis event for the safety Depressurization System (SDS) is the total _ loss of feedwater event. An analysis of this event and its mitigation by the SDS on System 80+ was provided in the response to Question 440.22 (Letter LD-91-018, E. H. Kennedy (ABB-CE) to USNRC, dated April 26, 1991.) The response stated that the event consequences would be more favorable than analytical results if the operator were to follow the steps in
" Combustion Engineering Emergency Procedure Guidelines,"
CEN-152, Revision 03. Those steps direct the operator from the optimal guideline for recovery from the loss of all feedwater to the functional guideline, HR-4, to recover the safety function for heat removal from the core and RCS.
The analyses give un assurance that the existing EPG's are fundamentally adequate and that additional guidance needs to be provided only to assure that the hardware' specific details represent System 80+. For example, SDS valves will be substituted for PORV's, the phrase " cold leg injection" will be changed to direct vessel injection and the S S coolant delivery curves will be changed to delete the LPSI_ contribution and to substitute the specific System 80+ HPSI delivery curves. Details for these changes will be provided in a Feed and Bleed Operational Guide which will be_ submitted in May 1992.
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Ouestion 440.128 Section 15.0.4 of CESSAR DC. states that for Chapter 15 design basis events-resulting in-a violation of the DNBR SAFDL limit, all offthe fuel rods experiencing _DNB are
- assumed-to fail.- The number of failed rods is calculated by the statistical convolution method. This method assigns a probability of occurrence of.DNB as a function of DNBR. This approach is not acceptable to the staff.
It is our position that all fuel rods violating the bHBR ,
SAFDL limit'(i.e., Transient MDNBR less than 1.24) are assumed to experience clad failure. Please provide revised analyses utilizing an acceptable approach.
Tha inadvertent-opening of a SG ADV (Section 15.1.4 of CESSAR-DC) assumed the loss of CEDMC reactor trip signal
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as the worst single failure and resulted in no fuel failure (i.e., the minimum hot channel DNDR remained above 1.24). palo Verde Unit 3 Cycle 2 assumed the loss of
- offsite power after turbine trip in conjunction with the inadvertent opening of a SG ADV and resulted in approximately 8 percent of the fuel rods experiencing DNB.
' In. view 1of this, justify why the single failure assumed in-the:CESSAR 80+-analysis of this event is the most limiting with respect to DNBR.
Resnonse' 440.121 ~
The validity of_the statistical convolution method in determining rods _in DNB for the Chapter-15 analyses-was -
described-in the response to RAI 450.01.
L The methodology used by-PVNGS Unit 3 Cycle 2 was based on p tui unrealistic l assumption that resulted in fuel damage for the Inadvertent Opening of a Steam Generator Atmospheric
- DumpL Valve plus a Loss of Of fsite- Power (IOSCADV- + LOOP)-
event. . The.-IOSGADV with an inadvertent turbine trip and -
coincident-loss of offsite power creates-a situation in which two_ initiating events _(IOSGADV-and: turbine trip) are I combined with a single failure (coincident loss of offsite- ,
power on; turbine trip). This scenario was avoided on- >>
ESystem: 80+ and a- more -credible one _ adopted. The justification for including a 3 second delay on loss of offsite power for System 80+ is provided in the response o to-RAI 440.85.
An analysis using the_CESSAR-DC methodology for the _
IOSGADV plus a single fallure of LOOP 3 seconds after turbine-trip resulted in radiological 1 consequences no more adverse than the submitted case in which the loss of CEDMC
. reactor trip signal was the single failure.
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Q12XQTION 450.09 The 0-2 hour X/Q value assumgd for ghe exclusion area boundary (EAD) is 4.97 x 10 sec/m . It should be noted that such a design X/Q value would preclude siting at about half of the currently licensed U.S. reactors sites, since analyzed LOCA thyroid doses (using this X/Q value) are nearly 300 rem. In addition, it is further noted that design approval assuming such a high X/O value would likely preclude approval of licensee request for use of fuel enrichment and/or burnup beyond that set forth in 10 CFR Part 51 Table S-4.
RESPONSE 450.09 ABB-Combustion Engineering agrees with the NRC's concerns.
The 0-2 hour X/Q and corresponding doses will be revised in a future amendment to CESSAR-DC.
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R EST10N 450 d2 Provide the basis for assuming on 15.6-12, a maximum airborne release fraction of 5 percent for primary to secondary leakage.
ESPONSE 450.12:
The CESSAR-DC dose methodology, which is consistent with the CESSAR-F methodology (letter LO-88-150 dated December 7,1988 from A. E. Scherer to G.
S. Vissing), conservatively assumes that the portion of the primary to secondary leakage which flashes (as it enters the secondary side of the steam generator, which is at a lower pressure than the primary side) is released directly to the atmosphere with an activity concentration equal to that for the primary fluid (i.e., the partition coefficient is 1). The unflashed portion of the leakage is assumed to mix with the existing SG liquid inven-tory. The steam release from this SG inventory is assumed to have a partition coefficient of 100, consistant with the guideline of the NRC Standard Review Plan (NUREG-0800). The foliowing discussion explains the calculation of the flashing fraction.
The flashed portion of the leakage is calculated using mass and energy balances on the fluid that leaks from the primary side to the secondary side.
This results in the following expression which is used to calculate the flashing fraction:
Flashing Fraction -
(h) - h ) / (h f g -h) 7 where, b) - er.thalpy of the primary to secondary leakage, Blu/lbm hp - enthalpy of the portion of leakage that remains as water at the SG secondary side (equal to enthalpy of saturated water at the SG secondary side pressure), Btu /lbm h - enthalpy of the portion of the leakage that changes to steam as 9 it enters the SG secondary side _ (equal to enthalpy of saturated steam at the SG secondary side pressure), Btu /lbm The CESSAR-DC dose methodology results in a time varying flashing fraction during the first 30 minutes after the initiation of the SGTR event.
The flashing fraction is time dependent since during the first 30 minutes the enthalpy values employed in Equation (3) change with time as the pressures and temperatures vary due to the reactor trip and opening of the SG main steam safety valves. Note that the affected SG is isolated at 30 minutes for the SGTR case analyzed in subsection 15.6.3.1 of CESSAR-DC. For this analysis, the flashing fraction is determined to vary between 1.3 and 5 percent and hence the maximum airborne fraction is identified to be 5 percent of the primary to secondary leakage.
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OVESTION 450.13 Please define the basis for the statement on P.15.A-14 that a maximum integrated radial peaking factor is assumed to be 1.58.
RESPONSE 450.13 The cycle maximum integrated radial peaking factor at full power, steady state conditions is used to calculate the radioactive inventory of the hot rod and thus the amount of radioactivity released during postulated accidents for which fuel failure is predicted to occur.
The use of a steady state fr is appropriate because the radioactive inventory of a fuel rod builds up over a relatively long period of time. The value of 1.58 conservatively envelops the maximum full power, steady state integrated radial peaking factor for potential fuel cycles for the System 80+ core.
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QUESTION 450.14 The assumptions for the SGTR event stated in SRP 15.6.3 are that the highest worth control rod is stuck in its fully withdrawn position.
Demonstrate the effects of this assumption on the SGTR radiclogical consequences.
ELSPpNSE 450.14 Since the STGR analyses demonstrated that there is no violation of the DNBR SAFDL for this event, there is no impact on the radiological consequences of assuming the highest worth control rod is stuck in its fully withdrawn position.
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l Question 450.15 The staff has evaluated the potential radiological consequences of the inadvertent opening of an atmospheric dump valve with loss of offsite power and has found that the postulated event may result in radiological consequences which exceed our acceptance criteria.
- Provide your analysis of this event using the criteria set forth in SRP 15.1.4.
Response 450.15 The evaluation of the inadvertent Opening of the Steam Generator Atmospherie Dump Valve (10SGADV) with loss of offsite power event that was performed resulted in no fuel failure as did the event presented in Chapter 15 (10SGADV with the loss of CEDMC trip signal). The results of both analyses thus conform to the acceptance criteria set forth in SRP 15.1.4. See the response to RAI 440.128 for additional information.
QU[1110N 480.3Eldl In accordance with SRP 6.2.4 Branch Technical Position Item 5, provide an analysis of the radiological consequences of a LOCA, taking into account the possibility of open purge valves. The source term used should be based on a calculation under the terms of Appendix K to determine the extent of fuel failure and the concomitant release of fission products, and the fission product activity in the primary coolant. The volume of the containment in which fission products are mixed should be justified, and the fission products from the above sources should be assumed to be released through the open purge valves during the maximum interval required for valve closure.
RESPONSE 480.37(d)
The information requested concerning the radiological consequences of a LOCA with the possibility of open purge valves is presented in Section 15.6.5 (Loss of Coolant Accident) and Section 6.3.3.5
. (Radiological Consequences) of CESSAR-DC. Table 15.6.51 presents offsite doses resulting from a LOCA and Table 6.3.3.5-1 presents the Source and Activity data assumed in evaluating the radiological consequences of a LOCA. The above information was derived from and consistent with Appendix K in determining the timing of fuel failure and the fission-product activity in the primary coolant with respect to the release contribution from the purge valves.
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. 4 OUESTION 730.6 Describe the guidelines to be used to develop procedures that call for the appropriate operator action during and following the steam line break incident.
RESPONSE 730.6 The Emergency Procedure Guidelines (EPG's) for a steam line break on System 80+ will be fundamentally the same as those provided in " Combustion Engineering Emergency Procedure Juidelines," CEN-152, Revision 03, for the Excess Steam Demand Event. Differences from the CEN-152 EPG's will be related to various hardware details on System 80+.
The only significant hardware improvement relative to the main steam line break is the addition of a cavitating venturi in the emergency feedwater line to each steam generator. The cavitating venturi acts, in a completely passive manner, to limit the flow rate to the affected steam generator when the downstream pressure falls. This limiting action lessens the urgency for the operator to identify and to isolate the affected steam generator.
Analyses in Chapter 15 of CESSAR-DC demonstrate acceptable results with essentially no operator action to isolate one emergency feedwater line.
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1 Ouestion 252.04 Section 5.2.4 In-Service Inspection And Testing of Reactor Coolant Pressure Boundary Section 5.2.4 states that " Specific code editions and addenda required by 10 CFR Part 50.55(a) are referenced in the Pressure Inspection (PSI) and ISI programs." The Pressure Inspection should be changed to Preservice Inspection.
Response 252.04-Section 5.2.4 will be revised to read, " Specific Code Editions and addenda required by 20 CFR 50.55(a) are referenced in the Pre-service Inspection.(PSI) and ISI programs".
Enclosure II_ presents a proposed revision to CESSAR-DC page 5.2-25.
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Ouestion__252.05 Section 5.3.2.1- P-T Limit Curves i
In Section 5.3.2.1.1.D.2, CE needs to provide values of sigma I and sigma delta for the reactor vessel beltline materials-for the calculation of the adjusted reference temperature. This-information is recommended in RG 1.99, Rev. 2, as a part of the reference temperature calculation.
Egsponse 251 05 Based on Regulatory Position 1.1 of RG 1.99, Rev. 2, the margin to be added to obtain conservative, upper-bound values of adjusted refogence temperature.(ART) can be calculated based on sigma I = -20 F = inigial RTndt (beltline) and a sigma delta =
28 F for wolds and 17 F for base metal. The resulting margin according to the equation M= ((sigma-I)2 + (sigma delta)2)1/2 is 39 F for welds and 29 F for base metal.
As indicated in Section 5.3.2.1.1 of CESSAR-DC, a margin of 50 F was used for both welds and base metal to provide an added degree of conservatism.
Also see Response 252.06.
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_QuestioD 252.06 Section 5.3.2.1 P-T Limit Curve Provide fracture toughness data and material specifications for all reactor vessel materials such as, initial RTndt, initial Charpy upper shelf energy, and chemistry contents.
Response 252.06 Reactor coolant system material specifications, including the reactor vessel, are given in Section 5.3.2.1 and Tabic 5.2-2.
Charpy upper shelf energies will comply with the requirements of 10CFR50, Appendix G, paragraph IVA, as described in Section 5.3.1.5 of CESSAR-DC. Actual material values cannot be provided prior to material procurement.
Also see Response 252.05.
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1 Ouestion 252.11 Section S.2.5.1.3 Leakage Through Steam Generator Tubes or Tube Sheet The description of detection and monitoring of primary to secondary leakage should be expanded. This has been the subject !
of HRC IN 88-99. Increased emphasis should be placed on state-of-the-art methods with special attention to the early detection .
t of rapidly increasing leakage rates which could be the precursor to a steam generator tube rupture.
Response 252_.11 The System 80+' design includes several provisions for detection and nonitoring of primary-to-secondary leakage._ The major methods of detection and monitoring are:
- 1. Condenser Steam Air Ejector Radiation Monitor - This radiation monitor is in continuous operation while the plant is at power, and will alarm at the main control panel on high gaseous activity. There is no bypass function as there was with the Indian Point 3 case highlighted in NRC Information Notice 88-99, so continuous monitoring can be maintained after initial, detection of primary-to-secondary leakage.
- 2. Steam Generator Blowdown Sample Line Radiation Monitors -
This monitor is in continuous operation while the plant is
-at power, and will alarm at the main control panel on high particulate activity in the blowdown liquid.
- 3. Main Steam Line Area Radiation Monitor - This monitor is in continuous operation while the plant ic at power, and will alarm at the main control panel en high radiation levels near the main steam lines, which would be indicative of a steam generator tube rupture.
These radiation monitors are described in CESSAR-DC Section 11.5.
Section:5.2.5.4.3 presents additional monitoring steps taken after identification of.a primary-to-secondary leak.
Early detection of increasing primary-to-secondary leakage is enhanced-by the Nuplex GO& control complex. Nuplex 80+ includes the capability to perform trending analysis on the radiation monitor output signals.
During the equipment procurement phase for a System 80+ power ,
plant, the actual raoiation monitors will be procured with consideration of the state-of- the-art technology availabic at that time.
Q astion 252.12 Section 5.4.2 Steam Generator The CE's response to Question 251.4 was not responsive with respect to the staff's inquiry on fluid elastic vibration. Provide data to substantiate the statement that damage from this mechanism is precluded.
Response 252.12 The design of the System 80+ steam generat rs, steam generator tubes, and tube supports precludes excessive vibration-induced damage. The steam gcnerator internals are designed to maintain localized fluid "clocities well below the critical velocities which will cause excesshe tut. libration. The horizontal "eggerate" tube supports are designed and located to maintain the natural frequency of the tubes higher than the exciting frequency induced by cross-flow in the tube bundle entrance region. Detailed vibration analyses are conducted for the ASME Code Section 111 Design Report prepared during fabrication.
High localized velocities in the tubc lanes near the outside corners of the cold side recirculating fluid entrance region caused flow-induced vibration and subsequent wear on a limited number of tubes in the System 80 steam generators tt Palo Verde. An evaluation of tube vibration, " Flow Distribution and Tube Vibration Evaluation of System 80 Steam Generator Tube Lane /
Economizer Corner Region", was submitted on the CESSAR-F Docket as Enclnsure (1) to Combustion Engineering letter LO-88 049. In comparison to the System 80 steam generators several design improvements, described below, have been made to the System 80+ steam generators to prevent the type of vibration-induced wear seen at Palo Verde (refer to the circled nnbers on the mark-up
. of CESSAR-DC Figure 5.4.2-3 attached):
- 1. The economizer divider plate and center stay cyiinder have been extended up to t'e top of the cold side recirculating fluid entrance window, to reduce 'luid cross flow velocities.
- 2. TF ncomer partition between h9t side and cold side has been extended a the top of the economizer divider plate to prevent circumferen-flow.
- 3. T . onomizer flow shroud has been extended up 16 inches to meet the dt mcomer flow shroud, for a circumferential distance of 7 inches on each side of the cold side recirculating fluid entrance window, to limit the cross flow velocities in the open tube lane along the economizer divider plate.
- 4. One additional "eggcrate" tube support has been added to the cold leg economizer region to stiffen the tubes (see CESSAR-DC Figure 5.4.2-2).
The combination of stiffer tubes and lower local fluid velocities results in a significant reduction in flow-induced tube vibration for the System 80+ steam generators.
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A flow induced vibration test has been performed on a test model for the steam generator economizer and lower tube bundle region. This test model incorporated the design improvements described above for the System 80+ steam generator.
The test L.odel was a full scale mock-up of a 22 degree sector of the cold leg with zero degrees corresponding to the centerline of the secondary side economizer divider plate. The model was bounded radially by a 52" innermost radius and an oute inost radius formed by the inside radius of the shroud.
Tubes were 18 feet in length extending from the tubesheet to two supported spans above the hwntomer recirculating fluid entrance window. A total of 482 tubes (.75 x .082 W.T.) were used in this model.
The test medium was ambient water flowing at velocities equivalent to the dynamic pressure of the operating unit at 100 percent power. Higher flow rates were tested up to 1.4 times the velocities calculated for 100 percent power. A three dimensional flow code was utilized in determining the entrance and exit velocities at various locations in the tube bundle. Strain gages and accelerometers were employed to measure tube response at the midspan between all supports.
Results from the test indicated that the maximum RMS displacement was about 0.9 mils or (.0009 inches) for a flow rate of 1.4 times the rate calculated for 100 percent power.
It should be noted that the economizer region of the steam generator that the test model was based on has a height of 132 inches above the tubesheet while that of.the System 80+ steam generators is 121 inches; both steam generators have the same number of lateral tube supports. Additionally, the spans above the economizer region are 17 percent shorter (34.0 in. vs. 39.72 in.) for the Systerr 80+.
Since the cold side recirculating fluid entrance velocity is roughly compara>1e between System 80+ and the tested steam generator design, the results of the economizer test should provide conservative results for the System 80+ units. Therefore, excessive tube vibrntion due to flow induced vibrations will not occur. I
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Question 252.13 USI A-49 Pressurized Thermal Shock (PTS)
The staff has revised equations 10 CFR Part 50.61 that calculate the limiting reference temperature, RTpts. The revision was published in the Federal Reaister, Volume 56, Page 223006 H"Y I r' '
1991. The revised equation will change the RTpts of 109 F that CE has calculated. CE needs to recalculate the RTpts and to revise the corresponding sectionc in CESSAR-DC.
Response 252 11 The updated RTpts has been calculated according to the revision of 10 CFR Part 50.61 as specified in the Faderal Reaister, Volume 56, Page 22300, May 15, 1991.
The new value for RTpts is 81 degrees F. Enclosure II presents proposed CESSAR-DC changes.
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., GSI 66 Stonw Generator Requirement i cE concludes that GSI 66 is resolved for the system 80+ doulgn because it meets industry codos br.d standards and SRP 5.4.2. The staff has savoral questions about the steam generator design an ,
shown above. The issuo will not be recolved until CE anoworn all !
of the staff's quantions natisfactorily. l Respsnan 252.1_4 Responses to the staff's questions on the System 80F ntonm ;
- genorktor donign are provided in Responsou 252.11 and 252.12. !
Steam generator chemistry is adarcased in Responacu 281.37, 201.30, and 281.40. ,
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_QMD11on_2E M The reference design t,hernuil insulation for CESSAR-DC in of the stainlena steel reflective type. Poor thermal performance of metallic ref1rctive insulation hau ocen experienced at neveral operatinq plants. Thic int 6ulation han also bean found to be nunceptible to phyt.ical damago. Several utilition have repinced the tantallic reflective insulation with norMtetallic insulation because of the poor thermai periornanco and damage particularly from foot traffic. 1:PRI-NP 29 64, " Control of Co.itainment Air Temperature and Inaulation Tent," providuc inforrtation on therrnal perfortnanco problemn with notallic reflective inst latien. In light of thin operational experience inctallic reficetive innulation, please provido your commento on the EPRI rtmort ani Why you have selected thin typo inculation, hcDv2nDL 2Wl'i Inculation and the heat loca associated with the inn'alation in not a cafety issue unlecc personnel protection becomen an incue duo to high inculat ion nurf ace toinperature or the containment air temperature approaches the design limit.
Report EPRI-NP-2694 han been reiowed. We are familiar with the limitationn of retallic irmulation a well an past inbibitions on uno of non-metallic insulation for J.OCA applicationc. An ovaluation was performed, reviewing the attributen of reflective metallic inculation vernus non-metallic innulation. Thin review indicaten that non-Inetallic insulation han been improved and ir, a viable candidate for System 804 insulation. CESSAR-DC Section 5.2.3.2.3 will be reviced allowing either metallic or non-metallic inculation to be used.
The third paragraph in Section 5.2.3.2.3 on page 5.2-18 will be replaced by a proposed new paragraph as chown in Enclocure II.
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_Questforg201.36_
i The applicant's ronponso -to lille quantion 281.20 indicated that the minimum and continuous pronaurizer spray flow donign capacities would be clarified. This clarification doon not appear to be in Section 5.4.10.
Rcjiponse 281.36 The responso to tfRC quantion 281.20 included an explanation of the proonuritor spray flow and bypnos flow. The responon also stated that Tablo 5.4.10-1 would be revisod to road that 375 gpm ;
is- the minimum design capacity, not the minimum design, spray .
flew. . It was ABB-CE's intent to include in CESSAR-DC only the !
, change to Table 5.4.10-1. The explanation in Rosponse 201.20 van ;
intended as supporting information for the reviewor's bonofit.
An additional change to Table 5.4.10-1 will-be mado to clarify ,
minimum design capacity spray flow and maximum continuous bypaso spray flow.
Enclosuro II presents a proposed rovinion to CEssAR-Dc Table 5.4.10-1.
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I Ouest; ion 281.42 The post-accident sampling connections for the safety injection system could not be located on riguro 6.3.2-1A as indicated in applicant's response tu HRC question 281-26. ,
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1 The post accidori sampling connections for the Safoty Injection l System are located off the minimum recirculation lines that return SI pump dischargo 1 low to the IRWST. Those connections are marked as " Sample Heat Exchanger" and aro located at coordinato G-4 of Figuro 6.3.2-1A (6.3.2-1B for SI pumps 2 and 4). One connection ir, provided for both normal and post ~ accident campling.
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As indicated it. applicant's response to NRC question 281-26, post-sceident sampling capabilities for the safety injection system Woro incorporated in Item K.3, Chemistry / Sampling in Amendment E. Amendment I has doloted this revision and should be re-incorporated.
JLqan;nso 281.43 This item was doloted in Amendment I because it was bnlieved to I be inappropriato for this section. This item addressos an !
interface with the process _ Sampling System. Because of the '
nature of tho-wording, this, entry was bo11oved to have boon more '
relovant to section 9.3.2, process Sampling System.
Enclosure II prosents proposed revisions to Section 9.3.2 of CESSAR-DC-to clarify this incuo.
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_Qslanlign 281.44 i
The post-accident nattpling connections for the shutdown cooling system could not be located on Figure 6.3.2~1A no indicated in applicant's response to NRC question 281-25.
Panon1L2RLdi Two post-accident carnpling connections are provided for the shutdown cooling system. One connection is located off the SCS pump suction line just upstream of the croco-connect to tne Containment Spray System. Thio 10 located at coordinate C-8 of Figure 6.3.2-1A. The second connection in off the inlet to the SCS Miniflow 11 eat Exchanger. This is located at coordinato B-5 of Figure 6.3.2-1A. Both connections are marked as "3ntnple !! cat Exchanger". Theno connections are utilized for both normal and post-accident campling.
Question 261.48 The applicant's responsa to NRC question 281-26 indicaten that CESSAR-DC Chapter 5 Section 5.4.7.1.3, Item K.5 will be rovined to roadt
- k. Chemistry / Sampling
-5. Post-accident sampling capabilition uhall be provided for the
- Shutdown Cooling Syntom. The sampling System shall be donigned to be consistent with the critoria specified in Item II.B.3, Post Accident Sampling Capability, of NUREG-0737, November 1980.
Incorporato this revision in Section 5.4.7.1.3-of Amendment I.
In addition, other chemistry nampling requirements in Section 5.4.7.1.3, page 5.4-24 of Amendment C have boon doloted.
Incorporate the following into Amendment It K. Chemistry / Sampling
- 1. The component cooling water shall contain corrosion inhibitors. Tho water shall not contain scalo-forming compoundo. The pit shall be controlled betwoon 8.3 and 10.5. Chlorido concentration shall bo losa than 1 0 ppm.
- 2. The Sampling Syntom shall provido a moann of obtaining remoto liquid samplea from the Shutdown Cooling System for chemical and radiochemical laboratory analynis.
- 3. The cumplo linos in crntact with reactor coolant chall be auntonitic stainless stool that in compatible with the fluid chemistry.
4.- The nample linen shall be sized auch the fluid I velocity allowa a representativo sample and the purgo flow rato is high enough to remove crud from the cample linco.
.Bosnonpo 281 31 The fivo chemistry / sampling interface requiremonta referred to in the question have not been incorporated into CESSAR-DC Chapter S Section 5.4.7.1.3 because they are presented olcowhere in the document as part of the completo System 00+ NSSS and Dop design. .
The CESSAR-DC Chapter 9 Amendment I noctions corresponding to Items K.1,-K.2, K.3, K.4, and K.5 aro-in Table 9.2.2-1, Section 9.3.2.2.2.D.1, Section 9.3.2.2.1.P, Section 9.3.2.1.3.G, and Section 9 3.2 2.2.D, respectively.
. _ . . - _ _ . - ._ _ _ _ _. .~. _. _ _ _ . . _ . . _ _ _ . . . _ _ _ - . . .
CMerAion_231d2 The summary description of the nuclear steam supply system balanco of plant interface requiromonts have bcon doloted in Amendment I.
Bosponne 20L11 The balance of plant (BOP) interfaco requirements were intentionally doloted from CESSAR-DC Section 5.1 by Amendment I.
Consistent with 10CFR, Part 52, requirements for certification of an " essentially complete" design, thoro is no lon9er a distinction betwoon 11ESS scope and BOP scopo. The BOP interface requirements removed from Section 5.1 either existed or were inserted in the chapters of CESSAR-DC which describe the design of the applicablo system. For examplo, the BOP interface requirements in Section 5.1.4.B.2 which addrosnod soismic categorios and ASMC classes for sections of the main steam piping woro doloted, because the sano information is promonted in Section 10.3.2.1.A. If a BOP interface requirement in Section 5.1 was not reflected in the appropriato system description, it was 6dded to the section describing that system.
Sito specjfic interface requirements are indicated in the text of the related system in CESSAR-DC. As stated in C-E lottor LD 054, dated October 22,1991, those interface requirements will be summarized in Doction 3.9 ofCESSAR-DC by February 1992.
1
Qungtion 281_.ftQ*
i
~
Detailed description of the steam gonorator is located in Section 5.4.2 of Amend. ment I. On page 5.4-14 of Section 5.4.2.4.1, it states that volatilo chemistry (discussed in Section 10.3.5) has boon successfully unod to minimizo corrosion in all CE steam generators that have gono into operation since 1972. To clarify -
this sentonce, delato (discussed in Section 10.3.5) and add a '
sentonce to read Secondary water chemistry and operating chemistry limits for secondary water and feodwater are discussed in Section 10.3.5.
Bosponso 281.Ja ,
. Section 5.4.2.4.1 will be revised as recommended. 500 the i proposed CESSAR-DC changes page 5.4-14 in Enclosure II.
- This question appears on page 7 of NRC lotter, T. V. Wambach to E. !!. Kennedy,-dated August 8, 1991, without a question number. Because it follown question 281.49, A1313-CE assigned number 281.50 to it.
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i
- * !!nclosure 11 to .
l_D 91071 l f
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L r ,
PROl'OSED REVISIONS TO Tile COMilUSTION ENGIN1?ERING STANDARD SAFETY ANALYSIS REPORT
+
,b I,
I i
W 7 4 7*+-9F y e4v_.s.gz% a% m,w,.-.. g.%,e.-, y , ,. .-, , ,..-.yfAs_,,wn,,ww,.m e e_44n..,,.e,w.ww,,, ,.,.,w,,_,,,.g_,,-... ,6w e . e,y., m- st -em me gbae. ww w h +, m. W wr .mwewr
, CESSARnabuou '
h.- es onst gyC-IQ - e
(
QQ55W The SITS contain boratod- water at a' concentration of 1.5 weight I percent boric acid Q g oo p y .
The tank gas / water fractions, gas pressure. and outlet pipe size are selected to allow tr/co of the four tanks to f3 cod and cover the core before significant fuel damage and before a significant zirconium-water reaction can occur following a LOCA. Yhe volume of water in the tanks is conservatively calculated ascuming that
, all water injected prior to the end of the RCS blowdown ja lost.
I Redundant levo) and pressure instrumentation (described in more detail in Svetion 6.3.5.3 and Tabic 7.5-2) are provided to monitor the condition of the tanks. Sufficient vis.a1 tind audibic indication are made available to the operator such that maintaining the SITS within the required technical specifications during various modes of plant operation is readily accomplished from the control room. Provisions have been made for sampling, filling, draining, and correcting boron concentration.
Atmospheric vent valvos are provided for tank venting. They are locked closed and the power to each valvo is removed during normal operation. This provents inadvertent SIT normal plant operation. venting during l1 s
6.3.2.2.3 Safety Injection Pumps (-.. )
The primary function of the Safety Injection (SI) pumps is tolc inject borated water into the PCS if a break occurs in the Reactor Coolant Pressure Boundary (RCPB). For small break LOCAs, 1 the RCS pressure remains high for a long period of time following lC the accident. and the SI pumps ensure that the injected flow is l t,uf ficient to meet the critoria given in Section 6.3.1. If necessary, SI pump flow is throttled to reduco RCS pressure to conditions that allow the initiation of shutdown cooling system operation for long term cooling. During shutdown cooling operations following a small break, the SI pumps continue injecting into the reactor vessc3 downcomer to provide makeup for spillage out the break.
I Long-term cooling for large break LOCAs is accomplished by manually realigning CI pumps 3 and 4 for simultaneous hot leg and iWI nozzle injection. This prov.idou flushing ilow and the ultimate subcooling of the core for those large break LOCAs that shutdown cooling cannot be used.
The SI pumps can be utilised to achieve safe shutdown by providing makeup for volume contraction and by providing sufficient boron to achieve and maintain necessary shutdown margins.
Amendment I 6.3-12 December 21, 1990
.CESSAREn!L mu
~ . ~
) yM--N#54 H VD .-
- f -l 3 .'._,
TAllLE 6. 3. 2_-1 (Cont'd)
(Sheet 2 of 3)
SAFl*rY INJECTION SYSTEM COMPONENT PARAMIf!'l:l(S Safety Injection __ Tanka Quantity 4 Safety Classification 2 Code ASME III, Class 2 Design Trossure, Internal / External 700 psig/100 poig Design Tempunture 200'F Operating Tempeature 120*F lr.
Hormal operating Pressure 610 psig 3
Normal Liquid Volume 26B8 ft I
Fluid porated Water, ~ _ _ . _
-M g $ 400 ppm g g.t.' < -
Material Clad - Stainless Steel, type 304, 316, or approved alternato Body - Carbon Steel, type SA-516 Gr.7 or approved alternate
{,
Amendment I December 21, 1990
CESSAR nMincuiou b.f 2 Q *O ll
- 3. Hegulatory Guide 1.71 Regulatory Guide 1.71 is discussed in Section 5.2.3.3.2.3.
5.2.4 IN-SMRVICE INSPECTION AND TESTING OF IEACTOlt COOLTMr PRESSURE BOUNDARY An In-service Innpection (ISI) program will be provided for the extamination of the Peactor Coolant Pressure Boundary (RCPB) componentn and supports defined as Code class 1. The program
'will reflect the principlen 'and intent embcdied in the ASMC Boiler and Pressuro Vessel Code,Section XI. Specific Code 1%'itio,ntL,and,addonda required by 10 CFR 50.55(a) are referenced lh the Pressure) Inspection (PSI) and ISI programs. The purpose y' of the LMerTico inspection program is to periodically inonitor the nystems or components requiring In-service Inspection in fOhorder
. to identify and to repair those indicationn which do not
> noot acceptance standards.
L to 5,2 The ISI Prcgrain aonnicts of three subprograms as follows:
A. The Component Inspection Program, which includes piping y
'- system volds, hangers, supports, internal inspection of pump and valvo bodies and bolting.
D. The Pump and Valve In-service Test (IST) Program, which requires operability testing of selected pumps and valves, and C. The Hydrostatic Test Program, which requires flow testing and hydrostatic testing of systems.
5.2.4.1 System Doundar'y subject to Inspection The reactor pressure vessel, pressurizer, primary side of the steam generator and associated piping, purnps , valves, bolting and component < supports are subjected to inspection.
5.2.4.2 Arrangement of Systems atid Components to Provide Mcess Wi[1ty l
The layout and arrangement of the pla..t provides adequate working l- space and access for insp?ction of specific areas of Code class 1 I
components of the RCPD in accordance with IWA-1500. The Code Class 1 components of RCPB subject to inspection are those componer.ts defined by ASME code Section III, Division 1.
l <,
1 l
Amendment I i
S.2-25 December 21, 1990
' C ES S A R !ai,%mou
(, D 2-, / 3 The design relief capacity C sach of two SCS relief valves (shown in P&ID Figure 0.3 ; . -
supplied by the vaDre manufacturer meets the minimum .. .ud relief capacity of 4000 gpm which contains sufficient margin in relieving capacity p' for even the worst transient. The SCS relief valves are Safety Class 2, designed to Section III of the ASME Code.
S.2.2.10.2.4 Administrative Controls Administrative controls necessary to implement the LTOP provisions are limited to those controls necessary to open the SCS isolation valves.
During cooldown, when the tempe rature of the RCS in abowa that corresponding to the intersection of the controlling P-T Limit and the pressurizer safety valve setpoint, overpressure protection is provided by the pressurizer safety valves, and no g administrative procedural controls are necessary. Ucfore entering the low temperature region for which LTOP is necessary, RCS pressure is decreased to below the maximum pressure required for LTOP. The LTOP pressure is less than the maximum pressure allowable for SCS operation. Once the SCS is aligned, no further specific administrative procedural controls are needed to ensure ,
proper overpressure protection. The SCS will remain aligned '
whenever the RCS is at low temperatures and the Ieactor vessel .,J head is secured or until an adequate vent has been established.[1 As designated in Table 7.5-2, indication of SCS isolation valve position is provided.
During heatup, the SCS isolation valves remain open at least until the LTOP enable temperature. Once the RCS temperature has reached that temperature correspondirig to the intersection of the controlling P-T Limit and the pressurizer safety valve setpoint, l overpressure protection in provided by the pressurizer cafety valves. The SCS can ba isolated and no further administrative precedural controls are necessary.
I E S.2.2.11 Pressurized Thermal Shock The System 80+ reactor vessel meets the requirements of 10 cru 50.61, " Fracture Toughness Requirenents For Prctection A 25 nat Pressurized Thornal Shock Events." The calculated RT p*P which patisfies the screening criteria in 10 CPR50.6kil)is (2).
S.2.3 REACTOR COOLMPP PRESSURE BOUNDARY MAT 13tJ ALS [) l l
S.2.3.1 Material Specification A list of specifications for the principal ferritic materialn, )
austenitic stainless steels, bolting and weld materialsf which '
are part of the reactor coolant pressure boundary is given in l Table 5.2-2.
Amendment I S.2-16 December 21, 1990
CES S AR nuiflCAllON Q 2..rb Or ()
These natorial and fabrication techniques and other reactor vessel design features era described as follows:
- The copper content is controlled to assure that the RT U will remain acceptable over the life of the plant.
The characterization of the steel and veel materials was established through industrial and governmental studies which examined the material properties in both the unirradiated and the irradiated condition. Inservice inspection and material surveillance programs are also conducted during the service life of the veasel, further ensuring adequate vessel integrity and safety margin.
Design, natorials of constructilon, fabrication methods, inspection requirements, shipment and installation, operating conditions, and inservice surveillance are all components of a program to assuro reactor vessel integrity for the plant design lifetime. A complete description of the reactor vessel design is given in CESSAR-DC, Section 5.3.
- The System 804 Standard Design reactor vessel is fabricated from ring forgings, thus climinating vertical volds in the .
beltline region where neutron irradiation is greatest. The eliuination of those particular welds further reduces the possibilities of impurities in veld material which are known to result. in an RT approaches the screening
- criterien of 270 degredb. that
- Furthermore, the System 804 Standard Design reactor vessel 8/
meets the requirements of 10 CPR 50.61 as described 10/
CESSAR-DC, Section 5.2.2.11. Specifically, the ScG~1ated RT et the end of the 60-year service life in . Q degrees F, 5 1ch is significantly below the screening crit)erion of 270 degrees F for plates forgings and axial wold materials, or 300 degrees F for circumferential weld materia {c.
N Since the System 804 reactor vessel design complies with the ASME code and other accepted industry codes and standards, and meets the requirements of 10 CFR 50.61, this issue is resolved for the System 80+ Standard Design.
RETIERtLCJR
- 1. liUREG-0933, "A Status Report on Unresolved Safety Issues",
U. S. Iluclear Regulatory Commission, April 1989.
Amendment F A-104 December IS, 1989
CESSARnahes - . - -
h ~2.$ / < 3[ '
Compatibility with External Insulat. ion and l
5.2.3.2.3 Environmental Atmosphere leakage of reactor coolant onto the reactor been The possibility ofvessel head causing corrosion of the pressure 3 boundary investigated by C-E. leakage onto coolant system reactor t affect Tests have shown that M surfaces of the reactor coolant pressure boursdary
~~
will no the integrity of the pressure boundary.
tTio s t q i,n e r.s teel /.
by opF is t f rupp ind
@qe ,. insula)tign r
wlt i miIrYiqiyeu l'nquiati(on?PQcpdf1containihtion/
ar x;r/ arc reficchve .ype, d4ccidh . solut,idtt spill'dgp/
I ac. tor oI ni'ckel\ based 41hy nozzh. in thd fed.
[evdptstaln1'6sd(a steef h,i i ves6hl hedf ','sm\and l
ll spct quahgity th ons of 'ngnfmetall'igf o.Geachdble inlog6nhxWill
/ ncu ht{on' areD gj .AlowcYer/the accord 6nce Dith Magulatory Gui'de_1.3 t
$ Fabrication and Processing of Ferritic Mater.ials 5.2.3.3 Fracture Toughness 5.2.3.3.1 HSSS Components 5.2.3.3.1..i for Reactor Coolant Pressure ASME Fracture toughness requirements established in accordance withtoughness Fracture the Boundary components are Section III.
Boiler and Pressure Vessel Code, affected zone materials will be testing of base, weld cnd heat Data from these conducted tests will beinavailable accordance afterwith thethe ASMEtesting required Code. has been perforned and may bL examined upon request at the appropria manufacturing facility. " Fracture Toughness C-E complies with 10 CFR Part 50 Appendix G, lD Requirements" as enscted May 1983.
consideration is given to the effects beltlineof irradiation region of the on material reactor in the corefracture toughness for the service toughness properties for discussion vessel to assure adequate Ref er to Section 5. 3.1.6 lifetime concerning of theprediction vessel. of irradiation offects and the complies with material the -
addition, C -E surveillance program, in Guide 1.2, " Thermal Shock to Reactor guidance of Regulatory Pressure Vessels." toughness tests for for fracture piping and ..
Testing and measuring equipment steam generators, pressurizer, accordance with [ )
the reactor vessel,pumps are calibrated in \ -/
reactor coolant Section III.
Subarticle NB2360 of the ASME Code, Amendment D September 30, 1988
_ ~ ~ - - -
5.2-18
2 G 2 8 I< )I Insert A, shown leelow, in to replace the third paragraph in '
Section 5.2.3.2.3 on page 5.2-18. The new paragraph will read: ;
_ (Insert A)
All metallic insulation used in the plant is of the stainless steel reflective type, which minimizes insulation contamination '
in the event of chemical solution spillage. All nonmetallic insulation used in the plant is designed to meet the requirements .
of Regulatory Guide 1.36, "lfonmetallic Thermal Insulation for Austenitic Stainless steel." complying with this Regulatory Guide assures that the nonmetallic insulation is designed in a rnanner which minimizes the potential for stress corrosion of stainless steel due to leaching of chloride or fluor.ide ions onto the stainless steel surfaces.
9 d
)
s
! a M M f_ i d d oh l 2 2/dd rmm1m a esmtims property parameter 2500 Design pressure, psia 700 Design temperatv*c, 'T flormal operating pressure, psia 2250 flormal operating temperature *f 652.7 3 2400 Internal free volume, f t 3 h tiormal (full power) operating ater volume, f t 1200 3 1200 flormal (full power) steam volume, ft 2400 r.
Installed heater capacity, LW lleater type immersion
,)
375 D Spray ficw, minimum design capacity, gpm 3 r.
pray flow, (maximum) continuous, gpm
% ?^
flozzles 12, schedule 160 Surge, in. (nominal)
Spray, in. (nominal) 4, schedule 160 Safety valves, in. (nominal) 6, schedule 160 lI; Instrument 3/4, schedule 160 Level, in. (nominal)
Temperature, in. (nominal) 1, schedule 160 pressure, in. (nominal) 3/4, schedule 160 Heater, 0.D., in. 1 1/4 Arnendment 1:
December 30, 1900
.- C ESS AR l'!#f,"icmon s
r) .
O ZF/, y 3 the point of origin. In addition, the offluent from analyzern which add chemicalc to samples (e.g., codium and U
silica analyzers) are routed to a high conouctivity wasto tank. Samplos that are radioactive or potentially radioactivo are segregated from non-radioactive campics.
. Sample syntom dischargon are returned to the system being campled (inntend of radwante) whenever possible. I
- c. Samplo riow Rate The sampic flow rate accurca turbulent flow (e.g., ne >
4000) in the sample line up-stream of the campling or 11 monitor,ing location. Samplo flow rato capabilitica are selected based on camplo line size, fluid temperature and samplo station location to annure that the turbulent . flow requiremont in act. A constant flow rato is maintained for continuous samples.
II. Post-Accident Campling I y-sm r v-~~ f A
- 1. The syntem is designcd to obtain reactor coolant y sampics 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. af ter plant shutdown and containment m
2 $U A Qg atnonphere aduplen 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> after plant shutdown, consistent with NUREG/CR-433.
v~
pasEK;' A %~ A 2, The design appropriately integrates the normal and n post-accident functions, co as to maximize the familiarity of plant operatorn with pont-accident operation (c). liowever, long sample delay times for I normal sampics are avo feL-_apd 11p;g h ,-
re FMt deqn utdszes cemn samp e i nu h^ nd_1.ing;t_isa3ggs_of4 g Nr norm min port ace d e.d .sofn p amd
- 3. 9ny tuMM1TTs7oTTierToTduring normal sampling operations hao testing capability to enabic periodic verification of operability and familiarization with r.ystem operation.
- 4. Provicion la nade for diluting liquid and gas camples "
for subsequent radiological analycio.
- 5. Collection and dilution of the pont-accident cample is performed remotely to the maximum extent feacible.
- 6. Grab samplen are utilized for specific laboratory analyses, and on-line monitorc are utilized for crends.
Utilizing grab samples for radioicotopic analysis is preferred over on-line monitorn. Gas chromatography E equipment is not utilized for on-line analysis.
Amendment 1 9.3-5 December 21, 1990
Q 2Mb 93
~[. nserF A :
Tu st{ stem is fo br designo( do be. consistent tol% +kt crite ria. speciRec( m Z+e m L 6. 3 ,. .
@ost Acdae.d sn,n p h y Capabilibj 3 .oR .
'~
.. JL4RE 6 ~ 0737. , Novem he ,1980. . ,
- * * * ' ' * * * *" =a ..... .... . . . - , . . ..., .. . ,
I 6
.s
- 40 e i
-- .___ - - - - - - , - - - - - - - - , - - , - - , - - , , - - - _ - - - - - - - - - - ----------"-s--------------------------------------s--- - - - - - - - -- - - - - --
4 i
C ESS A R "laf,"lCATION
&b3IN3 1
- 7. All remotely operated valyca required for pont-accident campling have assured power supplies and system level reset featuren which allow reopening of the valvoo after containment isolation without clearing the isolation signal for other containment inolation valves. Individual valve resot featuren are provided to allow opening of individual n mpling valven after system reset. Valven and operatoru which are inaccessible during an accident are environmentally g qttalified to ensure operability under accident conditions.
- 8. Two independent non-1E cources are availabic to provide electrical power for post-accident onmpling. After loss of normal of f-cito power, power in automatically supplied from on site. During lona of offsite power, I an alternate backup power cource, not necennarily the vital 1E bus, in available that ca gn .ne 4r. b3 ~ed in IB fricient time o neot mac Ami dheT5?i5i4T@rmyrop i-f4-}gt) c%WL-hmu vire meofs I n~-m -abovo. Yimemli,dt{
- SfLckst0 NUA[;ttg&'OT$T e I. Fire Protection m _
B In the event of a fire, reactor coolant boron compling N in available to verify shutdown margin, conciatent with 10 CPR 50, Appendix R. I 9.3.2.2 System Description 9.3.2.2.1 General System Description The proccas campling cystem includen sampling lines, heat exchangers, sample vescola, cample ainha or racks, analysin equipment, and instrumentation. The sampling points have been B selected to provide the required chemical and radiological information whi.'.e keeping the system simple for reliability and case of maintenance. Table 9.3.2-1 shows the sample locations,.
types of camples and monitors required for normal and post-accident nampling, respectively.
I Chemical and radiochemical analyses are portormed to determine fluid characteristics auch as boron concentration, fission and corrocion product activity, crud concentration, dissolved gas and i corrosion product. concentrations, chl.orido concentration, coolant l pH, conductivity of the reactor coo; ant, and noncondencible gan g concentration in the pressurizer. T1e results of the analyses are used to regulate the baron concontration, monitor the fuel cladding integrity, evaluate ion exchanger and filter performance, specify chemical additions to the various nystems, and maintain the proper hydrogen concentration in the reactor .
coolant system.
Amendment I 9.3-6 December 21, 1990
?
CESSAR Maincuiou
'L sl . 'l3 >
J. passive Flow Restriction Sample-lin+s which are not isolable from the RCS during E normal system operat. ions (including Shutdown Cooling System operation) are provided with a flow rostriction device (7/32" ID x 1" orifico) to limit the loss of coolnnt in tho event of a camplo lino piping break.
9.3.2.2.2 Detailed System Description In addition to the general system requirements discussed above, tho.. following specific sampling requirements ensure a reliablo I system. .-
A. Reactor Coolant System Samplos e
- 1. The sampling system provides a means of obtaining D remoto liqu b samplos fror, the Reactor coolant System for chemical and radiochemical laboratory analysis.
.~
Analyses are typically performed to datormino corrosion y product activity Icvols, crud concentration, dissolved l -gas and -corrosion product concentrations, chlorido D concentration, coolant pit, conductivity lovels and
- l d
-boron concentration. The results of thoso analyses are g 4 used to verify the boron concentration, monitor the fuoi rod integrity, specify chemical- additions and
, maintain the proper hydroccat conenn tion in -the RoantM- coolant Syst Shipliwq oF - t 15 pw&Wd QuM biM 6orma.4 h fost- ct c c d opera _n.o
+
- 2. Roa6I;or Coolant System samMedtione. Tro provided from-one hot leg and the pressurizer surge - line. A samplo connection is also provided from the pressurizer
, steam space via the pressurizer safety valvo inlet B -
piping. . F.ach of: these samplo. lines contains a '
- 7/32-inch by 1-inch orifico. This orlfico functions as the Safoty class 1 to Safety class 2 -boundary in the sample line per AllSI N18.2a - 1975. i 1
- 3. The high-pressure and high-temperature sampion from the -
pressurizer surge line, the pressurizer steam space and the hot leg are individually routed to a- sampling
-station whero they are first cooled in a sample heat exchanger -to 120'F or locs, and then reduced in pressure by a throttling valve to approximately 25 psig.--
'4. Provisions _are made to allow sampling of tho'Heactor l
Coolant System during startup. For this mode of ;
operation 'it can be assumed that the Reactor Coolant 3 System prensure in approximately 2S0 psig. .
Amendment I 9.3-10 December 21, 1990 ,
& &{ 0
- a. Vertical pipe, downward flow,
- b. Vertical pipe, upward flow. a
- c. !!orizontal pipe, vertical insortion.
- d. Alorizontal pipe, horizontal incertion.
S. All probes are 90 degreca to the pipe wall.
- 6. l'our campic pointo are provided for cach steam 3 generator:
- a. Hot log blowdown. 3
- b. Cold Icg blowdown.
- c. Recirculating (downcotter) water.
- d. Main Steam. I Samples from the blowdown linco originate as close to the blowdown nozzles an possible. Main steam campica g for each steam generator are extracted downstream of WF the Main Steam Inolation Valven (MSIVn), but upstream '
of the equalization header. All four camples (hot .
and cold leg blowdown, do.wnconer , and main atcam) run outside' containment without headering to allow independent simultaneous grab namples to bn drawn, and to allow the campics to be continuously monitored in accordance with Table 9.3.2-1. Alarms are provided for i all on-line monitors to alert operators of out of specification chemical conditions. ?
C. Safety Injection System Samples
- 1. Sainple points for the SIS are located in the
- a. Miniflow line for nafety injection pumps 1 and 3.
- b. Miniflow line n ~ foty injection pumpo 2 and 4.
pom 5 The above campic A ro de the operator w. na remote means of measur1. IRWST pli and boron concentration during an accident. These sainples are at a temperature of Icss than 350*F and a pressure of lenu than 2050 psig.Jh)A o[jiu $i5 5Ii55 f e r for<A6 n o r med p leol optrA f(ieVii h l] %'54' con,vdiovi5g Amendment I 9.3-12 December 21, 1990
1 l
CESSAR i'!aincuion l l
Q ] c?" l ~ V ?>
- 2. Local nampling linen are provided on the cafety injection tanks (four carnple pointa, one por tank).
Sampion from the safety injection tanku are at a pressure of lens than 700 polg and a teruperature of loss than 200'F. The valves on the namplo linen are y sized to limit flow to an acceptablo level at the aansple collection point.
- 3. Sanple taps are locate 6 on vertical runn of pipe whencycr possibic. Whero thin cannot be donc, it in permionible to take numpleo fron the top of horizontal pipo runs. The safety injection tanka are provided with cample nozzico. - - m dVttuu normd ud D. Shutdown cooling System Samplea - ed.4caud opurdsbq{
E
- 1. The Sampling System providen a racana of obta ning remote liquid camplea frota the Shutdown Cooling Syntet(
~
for chemical and radiochemical laboratory analys3c4 Four cample pointo are provided: .
o(tk
- a. SCS Miniflow !! cat Exchanger 1 4 m aig, 400*F).
- b. SCS Miniflow ilent Exchanger 2' psig, 400*F).
- c. Shutdown cooling pump 1 nuction line, (900 poig, 400*F). -
- d. Shutdown cooling purnp 2 auction line, (900 psig, 400'F).
' ' ~
Inlet
- 2. In addition to the camplo pointc/ escribed above, a I narnple tap la also provided in reach CS (Containment Spray) Miniflow IIcat Exchanger ^ lino (total of two taps). These tapa permit campling during shutdown cooling operations when a containment spray pump is being utilized. Theco tapa, an well as the SCS Miniflow IIcat Exchanger tapu, also permit sarnpling of the IRWST.
E. Gancouc Waste Ha'1agernent System Sarnplen
- 1. The Gas Analyzer Sampling System in designed to carnple the gas spaces of the following plant components and B discharge the campled gaa to either the mixing header (Mil) or the gas collectiors header (GCil) an indicated:
i i
A'w nd men t I 9.3-13 December 21, 1990
' C ESS AR IN!i"lCAfloN
~~
Q2-?7/.V3 ,
1ABLE 9.3.2-1 (Sheet I of
, PROCESS SAMPLING REQUIRINENTS y ,
HUIMEDPfRATIC Continuous !
Pressurized On Line Mode of Sample Analysis Sample l Sample Origin Capabillty ,_ Provided Removal .
Primary .iampling Hot Leg Icop 1 Yes Yes, Radio- Remote activity & Boron ,
Pressurizer Steam Space Yes None Remote Shutdown Cooling Suction .
No lione Remote i Lines 1 &-2 ,
QS, Shutdown Cooling System No Hone Remote Miniflow ileat Exchangerg Containment Spray Mini o No -
None Remote I i lleat Exchange aci i
ht)
Safety inject' ump No -None Remote:
Mini Flow-Lines Purification Filter Inlet , No Yes, Radio' Remoto- l
-activity & Boron
_ Purification Filter Outlet, No None Remote
_ ton Exchanger inlet .
Purificatton Ion Exchanger No None Remote Outlet- '
D Pressurizer Surge line No None- Remote Reactor Drain Pump Discharge No None Local Before filter-
~
- Reactor:0 rain Pump Discharge No None local
-After filter-Amendment I Docenber.21, 1990
1
. . I
' CESSAR EN!i"icuiou .
. t h 2 8/ Y3 \, ..!
TAD'E 9.3.2-1 (Cont'd) ,
($ bet 2 of [
PROCESS SAMPLING ktQU1 PEE NIS I NOIKOP11MT100-Continuous hessurtzed on Line Mode of 5ampie Analysis Sample
- Sample Origin capabilitj _ ,
Provided Removal PrimarySampling(Cont'd1 Pre-holdup lon Exchanger No None Local ~l Outlet !
7 lloldup Tank Inlet No None local Boric Acid Condensate Ion No None Local Exchanger Inlet Boric Acid Condensato Ion No None Local B Exchanger Outlet - -
Reactor Makeup Water Pump No -
None Local ,
Discharge Reactor Mohnt hter Pump No None Local RecirctlatGe -
Boric /$fo st< cup Pump No None 1.ocal Recirculation '
,- Boric Acid Hakeup Pump No Hone Local l
. Discharge L Boric Acid Batching Tank No None local l-t Reactor Hakeup Water to No None Local
! Volume Control Tank l: --Volume Control Tank Drain No None Local to Recycle Drain Header l-
_ lt Safety Injection Tanks- No None local -
m
\
1 I
Amendment I December - 21,_-1990
J :'CESSAR naincanou !
i Q7.g/.y3 ,
, TAllLE 9.3.2-1 (Cont'd) f (Sheet 3 of g ,
i PROCESS SAMPLING REf)UIRfMEN15 1
. W RW C OPERATIO F Continuous !
-Pressurized On Line Mode of Sample Analysis Sample Sample Origin Capability _ Provided u femoval
~~
Secondary Sample Points ,
llotwell- No Yes, cation Remote conductivity ,
and sodium :
S/G 1 and 2 Ilot Log Blowdown llo Yes, cation and Remote I
]
specific conduc-tivity, pil, lB ,
radioactivity, hh '*
sodium 7
S/G 1 and 2 Cold Leg Blowdown No Yes, cation and ' Remote
, specific conduc- .
tivity; pil, ln radioactivity, 1
sodium I S/G 1 and 2 Downcomer Water No Yes, cation and Remoto specific conduc-tit ity, pil,' ln radioactivity, sodium 1 .
.Condensete Pump Discharge No Yes, spectfic Remote ,
conducttvity, cation conduc-tivity, sodium,- B_ _
dissolv'ed oxygen ~ !
Process fampling System permits cor tinuous. chemistry monitoring of any I _;
two of these sample points for e4 :h steam generator, and continuous-radiation monitoring of any one of these sample points for each steam generator. .
Amendmerit I December 21, 1990-
l' CESSAR nainemiu i
bf/V3 O TAllLE 9.3.2-1 (Cont'd)
(Sheet 4 ofJ
?ROCESS SAMPLING REQUIREMENIS 1 N$lWCDprRATION Continuous Pressurized On Line Mode of Sample Analysis Sample Sampic Origin capability _ Provided Removal
'~
SecondarySamplepoints(Cont'dj Condensate Polishing _ !!o Yes, cation and Remote I Ocmineralizers Discharge specific conduc-tivity, sodium, dissolved oxygen Heater Drains No None local Moisture Separator Drains No- flone Local 1 Evaporator Drains
$;[
, No None . Local Secon'dary Steam S/G 1 & 2 No ,
Yes, cation Remote conductivity feedwater (llP tienters Outlet) No Yes, pil, oxygen, Remote I sodium,: cation and specific B conductivity, and
. hydrazine y Emergency feedwater Storage Tank No None Local Hakeup Effluent No Yes, conduc- Remote livity Domineralizer Water Tank No None t.ocal u condensato Storage Tanks Na None Local l
Aux Boller Fo Nonc local I
l Circulating Water No None local l Clused Cooling Water No Hone local n l' Systems ,
i-l Amendment I December 21, 1990 k- _ _
' CESSAR nainemou s3-
_h 1 8/.y 3 I
1 :
TAftLE 9.3.2-1 (Cont'd)
. - (Sheet 5 of PROCESS S(MPLING REQUIRENENT
'NTiERKlT6N Continuous B Pressurized On Line Mode of liample - Analysis Sa:nple Sample Origin Capability Provided Removal Secondary Sample Points (Cont'dl Emergency' Service Water. No Nonc local.
Spent fuel: Pool No None Local 1-Gas Sampling-Gas Surge Tank No 11 , 0 Remoto
_. 2 2 f Gas Decay Tank Yes 11 , 0 2 2 Remote Gas Stripper Yes 11 , 0 2 2 Remote Volume Control Tar.k No ' . 11 , 0 2 2 Remote a
- Equipment Drain' Tank No 11 , 0 Remote 2 2 i ' Reactor-Drain Tank No 11 , 0 2 2 Acm te .
'lloldup- Tank ,No- 112' 02 Remote--
Containment Atmosphere No Radianctivity Remote Cont inment Purge Exhaust - No Radioactivity- Remote I Plant Vent No Radioactivity P. emote Radioactive and Conventional No- Radioactivity Remote Waste System.
v -
<~
Post-Accident Sampling. System B llot leg Yes N/A Remote v . .
- Holdup Volume Tank No N/A Remote I J Containment Air No N/A Remote lB ' .,
.- --~~
Amendment I December 21, 1990
--__.b_-___ .___Z- <_m -' -, . , , - . . -
.y,-
S 2 F/ V3 Tdle 1. 3 . 2 - t ( cont 'd )
(5hed G oF G, )
Process s Am et. ine, Agpomeasurs . _
POS*r- A CC l DENT
~ ~ ~~
otE R ATibrJ '
Gnt.Avod' ' ~ ~ 31d of ~~~
O! '5 W LLtd Os Lba .
. Smpy
$ 4mplc Cri n __,
Ca ab 4 , , ,
Mmovd Hot Lc3 ~e l L .- . .b ... . . ._ .
"/A khN 99 9m98yit m- g g g, , ,
Gntamt Air No P/A % dc
%+, ur n %e . v. p .nu n1in\ Floo Lins ^
5%o4 du, Ceci, &% w gj, pwe 4.i a s - I & ;.
%hvidwm Cooli .g Ss%
t7 po gj,5 -
f.e. mote Dhat fl~ HealExanngec bltt Liq 3 m - ___ __ -- - _ _-- -__ __
, CESSARnabiou Q 2 F/,5T ([)
5.4.2.4.1 Steam Generator 'ntbes The method of fastening tubes to the tube sheet conforms with the requirements -of Sections III and IX of the ASME Code. Tube expansion into the tube sheet is total with no voids or crev. ices occurring along tha length of the tube in the tube sheet. After
- the tubing is installed in the steam generator and properly positione?, a seal weld is portormed betwoon the tubo and
, cladding on the primary side of the tubenheet. Subsequently, expansion of the tube in the tubesheet is performed using an explosive charge ("explancion"). Tolerances on charge length'and strength are specified so that the crevice between tube and tubesheet is closed through the full deptn of the tubesheet and so that no crevice occurs on the secondary face of the tubesheet.
Operating experience with this joint has been trouble-froe from the standpoint of secondary sloe corrosion at the tube-to-tubesheet interface and from the standpoint of primary nido stress corrosion cracking in the explanded portion of the tube.
The "explansion" proced'ure creates residual stress in the transition zone between the explanded and unexplanded regions of .-
tubing. Residual stress measurements have been performed on this 7 transition zone by X-ray diffraction. The results verify the '
absence of any high residual tenuile strees in the transition zone. Material 'sp'ecifications such as the use of thermally treated tubing, welding,.and fabrication procedures preclude the need for complete-bundle stress relief after assembly. 7 Operating C-E steam generators have experienced the following corrosion degradation mechanisms: phosphate wastage,. sulfate wastage, intergranular attack, secondary side stress corrosion cracking, and pitting and: denting resulting from tube support corrosion. With respect to these phenomena, the most important design feature of the System 80+ Standard Design steam generators is the selection of tubing and tubing support materials. For the System 80+ steam generators, Ni-Cr-Fe Alloy 690 in a therre.a lly treated (TT) condition is specified for the tubes. For the tube' supports, Stainless Steel 409 material is specified (see Tabic 5.2-2).
Volatile chemistry -(41-c= mcd u. seetu r . 10 . 3 .st-- h a s been successfully used to minim' e corrosion in all c-E steam generators that have gone into operation since 1972 Ramoval of solids from the secondary side of the steam Jonerator is discussed in Section 10.4.0.
~- m % m r y W '
Seconde y u>cler cheming and oper<thng chemisfnj Uniih for sea &y &# d hA"A>- a wsw= sed k See%o.35
- _,n - -
Amendment 1 S.4-14 December 21, 1990 j}