ML20057D207
| ML20057D207 | |
| Person / Time | |
|---|---|
| Site: | 05200002 |
| Issue date: | 09/27/1993 |
| From: | Mike Franovich Office of Nuclear Reactor Regulation |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 9310010258 | |
| Download: ML20057D207 (70) | |
Text
'
O September 27, 1993 Docket No.52-002 APPLICANT: ABB-Combustion Engineering, Inc. (ABB-CE)
PROJECT:
CE System 80+
SUBJECT:
PUBLIC MEETING OF JUNE 15 AND 16, 1993, TO DISCUSS REACTOR SYSTEMS RELATED OPEN ISSUES FOR THE CE SYSTEM 80+ STANDARD PLANT DESIGN On June 15 and 16, 1993, a public meeting was held at the ABB-CE offices in Windsor, Connecticut, between representatives of ABB-CE and the U.S. Nuclear Regulatory Commission (NRC). provides a list of attendees. is the material presented by the NRC, and Enclosure 3 contains information presented by ABB-CE.
The purpose of the meeting was to discuss the status of draft safety evalua-tion report open items and related follow-on questions. The staff provided an update on their review status of the System 80+ design. As a result of the meeting, a number of commitments were made in the areas of the:
Power upgrade and Chapter 15 reanalysis
=
Shutdown risk technical specifications Emergency core cooling bypass Technical specifications for the rapid depressurization system Performance / reliability of RDS for degraded core events Reliability of letdown line isolation valves during pipe break In the interim between this meeting and the issuance of this summary, another meeting was held July 7 and 8,1993. During the July meeting, a detailed listing of commitments and ABB-CE actions were provided in response to the June 15, 1993, meeting.
[
(Original signed by)
Michael X. Franovich, Project Manager Standardization Project Directorate Associate Directorate for Advanced Reactors and License Renewal Office of Nuclear Reactor Regulation
Enclosures:
DISTRIBUTION w/enclosuren As stated
- Docket? File PDST R/F DCrutchfield 4
'PDR MFranovich RPerch, 8H7 cc w/ enclosures:
TWambach SMagruder PShea See next page D_ISTRIBUTION w/o enclosures:
TMurley/FMiraglia R3orchardt JMoore, 15B18 EJordan, MNBB3701 MRubin, 8E23 SSun, 8E23 TGody. 17G21 ACRS (11)
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9310010258 950927 A
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w ABB-Combustion Engineering, Inc.
Docket No.52-002 cc:
Mr. C. B. Brinkman, Acting Director Nuclear Systems Licensing ABB-Combustion Engineering, Inc.
1000 Prospect Hill Road Windsor, Connecticut 06095-0500 Mr. C. B. Brinkman, Manager Washington Nuclear Operations ABB-Combustion Engineering, Inc.
12300 Twinbrook Parkway, Suite 330 Rockville, Maryland 20852 Mr. Stan Ritterbusch Nuclear Systems Licensing ABB-Combustion Engineering, Inc.
1000 Prospect Hill Road Post Office Box 500 Windsor, Connecticut 06095-0500 Mr. Sterling Franks U.S. Department of Energy NE-42 Washington, D.C.
20585 Mr. Steve Goldberg Budget Examiner 725 17th Street, N.W.
Washington, D.C.
20503 i
Mr. Raymond Ng 1776 Eye Street, N.W.
Suite 300 Washington, D.C.
20006 Joseph R. Egan, Esquire Shaw, Pittman, Potts & Trowbridge 2300 N Street, N.W.
Washington, D.C.
20037-1128 Mr. Regis A. Matzie, Vice President-r Nuclear Systems Development ABB-Combustion Engineering, Inc.
l 1000 Prospect Hill Road Post Office Box 500 Windsor, Connecticut 06095-0500 l
r
ABB-CE SYSTEM 80+
Reactor Systems Meeting Windsor, Connecticut Jyne 15.1993 NAME ORGANIZATION M. Rubin NRC/DSSA/SRXB M. Franovich NRR/PDST S. B. Sun NRC/NRR/SRXB M. Cross ABB-CE F. L. Carpentino ABB-CE J. Rezendes ABB-CE T. K. Samuels ABB-CE J. Robertson ABB-CE M. Volodzko ABB-CE C. B. Colgman ABB-CE
[
J.Longo ABB-CE S. Ritterbusch ABB-CE R. Mitchell ABB-CE J. Rec ABB-CE June 16.1993 M. Rubin NRC/DSSA/SRXB M. Franovich NRR/PDST S. B. Sun NRC/NRR/SRXB D. T. Diec NRC/DSSA/SRXB R. Mitchell ABB-CE R. Ivany ABB-CE F. I. Carpentino ABB-CE S. Ritterbusch ABB-CE P. Hansen ABB-CE/FSE l
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STATUS OF OPEN ISSUES FOR SYSTEM 80+(DRAFT)
A1 These open items are considered to be technically resolved subiect to confirmation of inclusion of resolutions in CESSAR-DC 1.*
4.3.2-1 Positive MTC in the Technical Specification 2.
4.3.2-2 Compliance with 10 CFR 50.6 Regarding Neutron Fluence 3.
5.4.3.1-2 Boron Mixing Under Natural Circulation Conditions 4.*
5.4.3.2-1 Valve Position Indication in CR for Isolation Valves in SCS 5.*
5.4.3.2-2 Design and Procedure Improvement for SCS Overpressure Protection 6.
5.4.3.2-3 Diversity of Interlock for SCS Isolation Valves 7.
5.4.3.4-1 Durability of SCS Pumps 8.
6.3.1-1 HPSI Flow at Low Pressures RD5 9.
6.7.2-1 10-Minute Operator Action Time in Sizing,RGGVS Valves 10.*
15.1-1 Reactivity Feedback Functions Used in the Transient Analysis 11.*
15.1-2 Convolution Method for the Fuel Failure Calculations 12.
15.1-3 Deviations from EPRI URD (in the SRXB Review Areas) 13.
15.1-4 3-Second Loop Delay Time 14.
15.1-5 GDC-17 Compliance 15.*
15.3.1-1 Justification for Use of the Peaking Factor of 150 for the SLB Analysis 16.
15.3.2-1 FLB Reanalysis to Address 3-Second Loop Time and SG HX Model 17.
15.3.6-1 Verification of the Worst LOCA with Maximum SI Flow 18.
15.3.8-2 Technical Basis for SG Overfilling Prevention during an SGTR
-a 19.*
20.1-05 GSI-A-26 Regarding LTOP Requirements 20.
20.1-07 RCP Seal Injection (GSI-23) 21.*
20.2-12 The TS for LTOP 22.
20.3-1 II.K. 3 (2) - PORV Reliability
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The onen item is expected to be reclassified as a COL action item:
23.
4.4.4-1 CPC/CEAC Software. Changes and Testing
' Note:
For the items with *, no additional informational is needed for the closeout of the open items.
j C.
The open items remainina Open:
(I)
The staff is waiting for additional information to be provided by CE for the following items:
1.
5.4.3.1-1 Natural Circulation Cooldown per BTP RSB 5-1 2.
5.4.3.2-4** Intersystem LOCA for SCS 6
3.
6.3.2-1**
6.7.1-2**
ITAAC for RCGVS Valve Flow 5.
6.7.2-2**
ITAAC for RDS Valve Flow 6.
6.7.2-3 Reliability of RDS for Severe Accident
{
Mitigation i
7.
6.7.2-4 EPG for RDS
{
8.
15.3.5-1 Reliability of Relief Valves in the Letdown Line, Sample Line and Instrumentation Line upon l
Demand during Breaks 9.
20.2.14**
Intersystem LOCA (GSI-105) 10, 7.2.2.2-1 I & C Diversity 11.
7.2.2.6-1 Information Notice 92-54 Level Instrumentation Accuracy 12.
3.9.1-2 Bases for Stress Analysis (II) The staff is reviewing the newly submitted material by CE for the following issues:
j 13.
5.4.3.5-1 Shutdown Risk i
~
14.
5.4.3.5-2 Shutdown Risk (RAI 440.140-151) i 15.
6.3.3-1**
Reliability of SI Pumps at the Mini-Circulation Mode 16.
6.7.1-1 EPG for RCGVS l
17.
15.2.2-1 Acceptability of LOCV Analysis I'
18.
15.3.1-2 SLB and Post-LOCA Reanalysis 19.
18.9.2-1 EPG Review l
20.
20.2-3 Shutdown' Risk (GSI-99) 1 21.
DSER-15 Accident and Transient Reanalysis
-(
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The open issues and confirmatory item were oriainally assioned to SRXB and were subseauently transferred to other Review Branches (See letter of R.
Jones to R.
Pierson, dated November 27. 1992):
Review Item Number Type Subiect Branch 1.
6.7.2-1 Confirmatory To confirm that SCSB the criterion of 250 psia for pre-clusion of a direct containment heat challenge 2.
5.4.3.2-4 Open GSI-105 (Inter-ESGB system LOCA)
SRXB ESGB is to review the stress analysis portion of the issue 3.
15.3.8-1 Open To evaluate the SCSB potential benefit of mitigation features for con-tainment bypass due to a SGTR 4.
20.3-1 Open TMI Action Item SCSB II.D.1.1-Primary Coolant Sources outside the Containment Structure.
E.
The confirmatory items remainina to be confirmed:
1.
4.2.7-1**
ITAAC for Fuel-Design Acceptance Criteria l
2.
6.3.8.1**
G.7.1.1 TSs for SDS 5.
DSER 4.4.3 LPMS-The Applicant is Required to Provide a Description of Procedures and/or Maintenance Program to Assure the LPMS Operability.
Otherwise, a TS is Required in Accordance with RG 1.133,REV.
1.
- Note:
For items with **, satisfactory resolutions may affect the ITAAC review schedule.
i
l 440.231 ECC Bypass During LBLOCAs As referenced in the MPR-1329 report of September 1992, prepared by MPR Associates Inc., the results of ECC bypass tests performed in the Upper Plenum Test Facility (UPTF) indicated that ECC injected directly to the downcomer nozzle near the broken cold leg was predominately bypassed and thus contributed little to the ECC penetration during the end-of-blowdown / refill tests.
The penetration of ECC was due to injection to the nozzle away from the I
broken cold leg.
For tests with vent valves in the core barrel, the penetration of downcomer ECC was comparable to the penetration found for the cold leg ECC injection.
For tests with no vent valves, ECC penetration was less than in the cold leg injection tests. The analysis in the MPR-1329 report also indicated that 40 to 50 percent of the injected ECC apparently bypassed the downcomer during the reflood tests.
Has ABB/CE considered the UPTF ECC bypass test data for determination of ECC bypass in the System 80+
LOCA analysis?
In light of the UPTF tests, ABB/CE is requested to provide a description of the LOCA model for calculating the ECC bypass during the blowdown, erid-of-blowdowm/ refill and reflood phases of the LOCAs, and justify its conservatism by comparing the applicable ECC bypass test data (including the described UPTF tests, if they are applicable to the System 80+ design.)
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SYSTEM 80+ CHAPTER 15 REANALYSIS FOR POWER UPGRADE 1
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JUNE 16',
1993 i
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ABB-COMBUSTION ENGINEERING, INC.
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' SYSTEM 80+ CHAPTER 15 REANALYSIS FOR POWER UPGRADE O
CHANGES INCLUDED IN THE SYSTEM 80+ REANALYSIS h
O DISCUSSION OF LIMITING EVENTS-i
-CHANGES TO THE EVENT DEFINITION 1
-SIGNIFICANT ANALYSIS CHANGES t
-IMPACT ON RESULTS i
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SUMMARY
OF CHANGES INCLUDED IN THE i
SYSTEM 80+ REANALYSIS I
O THE NOMINAL REACTOR COOLANT INLET TEMPERATURE IS DECREASED FROM. 558 F TO 555.8 F O
CORE POWER WAS INCREASED FROM 3800 MWT TO.3914 MWT O
THE INITIAL CONDITION SPACE FOR THE CHAPTER 15 ANALYSES WAS CHANGED AS FOLLOWS:
AMENDMENT H AMENDMENT N CORE POWER, % OF FULL POWER 0-102 0-102 PRESSURIZER PRESSURE, PSIA 1905-2375 2175-2325 CORE INLET TEMPERATURE,
< 90% POWER, F
543-565 543-561 90% - 100% POWER, F
553-563 550-561 O
AN INTEGRAL BURNABLE POISON WAS SUBSTITUTED FOR SHIM RODS (WITH THE USE OF INTEGRAL BURNABLE POISON, THE 3914 MWT FULL POWER CORE AVERAGE HEAT FLUX IS LESS THAN THAT FOR THE 3800 MWT CORE DESIGN)
O THE MOST POSITIVE MODERATOR TEMPERATURE COEFFICIENT AT FULL POWER HAS BEEN REDUCED FROM 0. 0 TO -0.1 X 10" DELTA-RHO / F
[
O THE CEDM HOLDING COIL DECAY' TIME HAS BEEN DECREASED FRCM 0.8 SEC TO 0.5 SEC O
THE UNCERTAINTY ON THE MAXIMUM PRIMARY SAFETY VALVE OPENING SETPOINT HAS BEEN INCREASED FROM 25 PSIA TO 40 PSIA O
FINAL DESIGN DETAIL INCREASED THE ASSURED FLOW RATE i
THROUGH THE PRESSURIZER SAFETY VALVES FROM 460,000 LBM/HR TO 525,000 LBM/HR THE TIME DELAY FOR L'SS OF OFFSITE POWER FOLLOWING O
O TURBINE TRIP WAS DECREASED FROM 3 SECONDS TO O l
SECONDS 9
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SUMMARY
OF CHANGES INCLUDED IN THE SYSTEM 80+ REANALYSIS (CONTINUED)
~
O THE MAXIMUM MAIN FEEDWATER SYSTEM FLOW WAS INCREASED FROM 140% TO 160%
O THE MAXIMUM CHARGING FLOW TO THE RCS WAS DECREASED TO 150 GPM I
O THE STEAM GENERATORS HAVE BEEN REDESIGNED (E.G. THE NUMBER OF TUBES HAS INCREASED) i O
FINAL DESIGN DETAIL INCREASED THE SURGE LINE LENGTH BY 25 FEET O THE DIAMETER OF THE DIRECT VESSEL INJECTION LINES WAS INCREASED NOMINALLY FROM 10 TO 12 INCHES O
THE LETDOWN LINE FLOW RESISTANCE HAS BEEN INCREASED O
THE SITE ATMOSPHERIC DILUTION FACTORS, X/Qs, WERE CHANGED TO THE EPRI URD VALUES O
THE OFFSITE DOSES FOR EVENTS INVOLVING FUEL FAILURE WERE COMPUTED USING THE NUREG-1465 SOURCE TERM O
THE TORC COMPUTER CODE WAS USED INSTEAD OF THE CETOP CODE TO COMPUTE THE MINIMUM DNBRs FOR THE FEEDWATER 4
LINE BREAK AND LOCKED ROTOR ACCIDENTS 6
ca5 S
8sn y
MOST LIMITING h
FUEL LICENSING h
LIMIT REQUIRED TOLERANCE MARGIN (E.G. INSTRUMENT ERRORS, MANUFACTURING TOLERANCES, EQUIPMENT CAPABILITIES, ETC.)
u l
5 C
FsEQUIRED MARGIN FOR MOST LIMITING g
Qg LICENSING BASIS LIMIT E5 c-6 o
w YW o
n-AVAILABLE MARGIN FOR OPERATIONS (157. MINIMUM) o E
t-2 v
3 RATED POWER h
NORMAL FUEL OPERATING RANGE y
v ZERO POWER Figure 4.2-1 ALWR Fuel Thermal Margin Page 4.2-4
r 15.1.4 INADVERTENT OPENING OF A STEAM GENERATOR ATMOSPHERIC DUMP VALVE r
O EVENT DEFINITION CHANGE
- ZERO TIME DELAY ON LOSS OF OFFSITE POWER
- LOSS OF OFFSITE POWER CONSIDERED AS PART OF THE EVENT (NO RECATEGORIZATION)
O SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASED
- INITIAL DNBR INCREASED FROM 1.52 (AMENDMENT H) TO 1.62 (AMENDMENT N)
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N)
{
- AMENDMENT H ANALYSIS CHOSE AN INITIAL DNBR SUCH THAT THE RESULTING TRANSIENT MINIMUM DNBR AT 30 MINUTES WAS 1.24.
AMENDMENT N 30 MINUTE DNBR 1.36 f
O IMPACT ON RESULTS j
- ROPM, DECREASED COIL DECAY TIME, AND CHANGE IN l
i ANALYSIS METHODOLOGY ALLOWS EVENT TO ACCOMODATE LOSS OF OFFSITE POWER WITHOUT FUEL j
FAILURE AMENDMENT H AMENDMENT Q EVENT W/O A SINGLE j
FAILURE l
MINIMUM DNBR 1.24 1.30 EVENT WITH A SINGLE FAILURE MINIMUM DNBR 1.24 1.29 l
B-A.i D
15.1.5 CASE 5 i
FULL POWER OUTSIDE CONTAINMENT STEAM LINE BREAK O
EVENT DEFINITION CHANGE LOSS OF OFFSITE POWER ASSUMED COINCIDENT WITH REACTOR-TURBINE TRIP O
SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASE
- INITIAL DNBR 1.62 (AMENDMENT Q) VERSUS AMENDMENT H VALUE OF 1.53
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMEITI' N) l
- THE MODERATOR TEMPERATURE COEFFICIENT HAS CHANGED FROM -5. 4 X 10-' DELTA-RHO / F (AMENDMENT H) TO -3.5 X 10-4 DELTA-RHO / F (AMENDMENT N)
- NUREG 1465 SOURCE TERM
- EPRI X/Qs O
IMPACT ON RESULTS l
- DNBR AND FUEL FAILURE IMPROVE DUE TO ROPM, COIL-DECAY TIME, AND MTC 1
- DOSE CHANGE SMALL DUE TO LOWER IODINE RELEASES I
(NUREG-1465) AND HIGHER X/Qs AMENDMENT H AMENDMENT N MINIMUM DNBR 1.18 1.25-q FUEL FAILURE 0.5%
0.5% (ASSUMED)
.an.,
l 15.1.5 CASE 6 ZERO POWER STEAM LINE BREAK OUTSIDE CONTAINMENT WITH LOSS OF OFFSITE POWER e
O EVENT DEFINITION CHANGE
- NO CHANGE i
l 0
SIGNIFICANT ANALYSIS CHANGES
- COLD LEG TEMPERATURE OF 565 F (AMENDMENT H)_ REDUCED TO 561 F (AMENDMENT N):
LOWER INITIAL SG PRESSURES
- EPRI X/Qs O
IMPACT ON RESULTS i
- LOWER MASS RELEASE DUE TO LOWER INITIAL SG PRESSURES
- DOSE INCREASES DUE TO INCREASED X/Q CHANGE: LOWER MASS RERLEASE HAS SMALL EFFECT AMENDMENT H AMENDMENT N MASS RELEASED l
FROM AFFECTED SG 623,000 LBS 571,000 LBS (2 HOUR) 2._ HOUR THYROID DOSE PIS 15 REM 28 REM j
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-15.2.3 LOSS OF CONDENSER VACUUM O
EVENT DEFINITION CHANGE
- ZERO TIME DELAY FOR LOSS OF OFFSITE POWER
- LOSS OF OFFSITE POWER CONSIDERED AS PART OF THE EVENT (NO RECATEGORIZATION) t t
O SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASED q
l
- INITIAL DNBR INCREASED FROM 1.53 (AMENDMENT H) TO 1.63 (AMENDMENT N)
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N) 3% POWER UPGRADE IMPACTS PEAK PRESSURE l
- PSV LIFT PRESSURE UNCERTAINTY INCREASED FROM 25 PSI (AMENDMENT H) TO 40 PSIA (AMENDMENT N) l
- COLD LEG TEMPERATURE REDUCED 3 F i
i O
IMPACT ON RESULTS 4
- DNBR IMROVES DUE TO LOSS OF OFFSITE POWER COINCIDENT WITH TURBINE TRIP:
EVENT WITHOUT LOSS OF OFFSITE POWER IS LIMITING l
l
- ROPM AND DECREASED COIL DECAY TIME ALSO IMPROVE i
DNBR l
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- PEAK RCS PRESSURE INCREASES DUE TO INCREASED POWER-AND PSV LIFT PRESSURE, AND REDUCED COLD LEG TEMPERATURE
'l
t 15.2.3 l
(CONTINUED)
O IMPACT ON RESULTS AMENDMENT H AMENDMENT N i
MINIMUM DNBR 1.07 1.26 i
FUEL FAILURE 1.8%
0.0%
PEAK RCS PRESSURE 2707 PSIA 2726 PSIA i
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15.2.8 FEEDWATER LINE BREAK O
EVENT DEFINITION CHANGE
- ZERO TIME DELAY FOR LOSS OF OFFSITE POWER O
SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASED
- INITIAL DNBR INCREASED FROM 1.56
(. AMENDMENT H) TO 1,62 (AMENDMENT Q)
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N)
- 3% POWER UPGRADE IMPACTS PEAK PRESSURE
- PSV LIFT PRESSURE UNCERTAINTY INCREASED FROM 25 PSI (AMENDMENT H) TO 40 PSIA (AMENDMENT N)
- PSV MINIMUM FLOW RATE WAS INCREASED FROM 460,000 LBM/HR (AMENDMENT H) TO 525,000 LBM/HR (AMENDMENT N)
- SURGE LINE LENGTH WAS INCREASED BY 25 FEET
- INITIAL PRESSURIZER PRESSURE INCREASED FROM 1971.3 PSIA (AMENDMENT H) TO 2175 PSIA (AMENDMENT N)
- THE TORC COMPUTER CODE WAS USED TO CALCULATE MINIMUM DNBR AS OPPOSED TO THE CETOP CODE USED FOR THE AMENDMENT H ANALYSIS
- NUREG-1465 SOURCE TERM
- EPRI X/Qs j
i
15.2.8 3
FEEDWATER LINE BREAK (CONTINUED) r O
IMPACT ON RESULTS
- DNBR MORE ADVERSE DUE TO PSV BLOWDOWN
- PEAK RCS PRESSURE INCREASED DUE TO HIGHER PSV OPENING PRESSURE, H1GHER POWER LEVEL, AND INCREASED SURGE LINE LENGTH
- PEAK SG PRESSURE IS REDUCED DUE TO A LARGE BREAK 2
BEING THE LIMITING BREAK FOR AMENDMENT N (O.7 FT_
VERSUS 0.3 FT FOR AMENDMENT H) 2
- DOSE INCREASES DUE TO FUEL FAILURE AND X/Qs AMENDMENT H AMENDMENT N AMENDMENT Q MINIMUM DNBR 1.56 1.21
?
FUEL FAILURE 0.0%
0.15%
?
PEAK RCS PRESSURE 2720 PSIA 2785 PSIA
?
PEAK SG PRESSURE 1251 PSIA 1189 PSIA
?
I 2 HOUR THYROID 8.3 REM 22.9 REM
?
DOSE 4
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t 15.3.1 TOTAL LOSS OF REACTOR COOLANT FLOW O
EVENT DEFINITION CHANGE t
- NO CHANGE:
LOSS OF OFFSITE POWER ORIGINALLY (AMENDMENT H) CONSIDERED EVENT INITIATOR i
O SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASED
- INITIAL DNBR 1.62 VERSUS AMENDMENT H VALUE OF 1.53
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N)
- COLD LEG TEMPERATURE REDUCED 8 F:
- INITIAL PRESSURIZER PRESSURE FOR PEAK PRESSURE CASE REDUCED FROM 2425 PSIA (AMENDMENT H) TO 2325 i
PSIA (AMENDMENT N)
- PSV LIFT PRESSURE UNCERTAINTY INCREASED FROM 25 PSI (AMENDMENT H) TO 40 PSI (AMENDMENT N) l
- THE FULL POWER MODERATOR TEMPERATURE COEFFICIENT CHANGED FROM 0. 0 ( AMENDMENT H)' TO - 0.1 X 10-* DELTA-l RHO / F (AMENDMENT N) 1
- THE INITIAL AXIAL POWER SHAPE CHANGED FROM AN ASI OF 0.0 (AMENDMENT H) TO +0.3 (AMENDMENT N) l
- 3% POWER UPGRADE IMPACTS PEAK PRESSURE i
es
i 15.3.1
~
TOTAL LOSS OF REACTOR COOLANT FLOW (CONTINUED) l O
IMPACT ON RESULTS
- MINIMUM DNBR IMPROVED
- LOWER COLD LEG TEMPERATURE REDUCES PEAK SG PRESSURE AND INCREASES PEAK RCS PRESSURE
[
-HIGHER POWER AND PSV SETPOINT INCREASES PEAK RCS PRESSURE AMENDMENT H AMENDMENT N MINIMUM DNBR 1.24 1.27 PEAK SG PRESSURE 1274 PSIA 1249 PSIA PEAK RCS PRESSURE 2636 PSIA 2652 PSIA 4
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-c 15.3.3 l
ROTOR SEIZURE O
EVENT DEFINITION CHANGE
- ZERO TIME DELAY FOR LOSS OF OFFSITE POWER
.l O
SIGNIFICANT ANALYSIS CHANGES l
t
- ROPM INCREASED
}
- INITIAL DNBR 1.62 (AMENDMENT Q) VERSUS AMENDMENT H I
VALUE OF 1.57 i
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8
[
SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N)
- PSV LIFT PRESSURE UNCERTAINTY INCREASED FROM 25 PSI (AMENDMENT H) TO 40 PSIA (AMENDMENT N) f
- INITIAL PRESSURIZER PRESSURE FOR PEAK PRESSURE CASE REDUCED FROM 2400 PSIA (AMENDMENT H) TO 2325 PSIA (AMENDMENT N)
- COLD LEG TEMPERATURE REDUCED 9 F FOR PEAK PRESSURE CASE i
- THE FULL POWER MODERATOR TEMPERATURE' COEFFICIENT
-l HAS CHANGED FROM 0.0 (AMENDMENT H) TO -0.1 X'10+
I DELTA RHO / F (AMENDMENT N)
- THE INITIAL AXIAL POWER SHAPE WAS' CHANGED FROM AN-ASI OF -0.3 (AMENDMENT H)'TO +0.3 (AMENDMENT N) l
- NUREG-1465 SOURCE TERM
~!
- LOWER AND CONSTANT SG INVENTORY FOR' AMENDMENT.H DOSE ANALYSIS, HIGHER AND VARIABLE SG INVENTORY FOR l
AMENDMENT N CALCULATION f
- EPRI X/Qs l
r
i 15.3.3 I
ROTOR SEIZURE (CONTINUED)
O SIGNIFICANT ANALYSIS CHANGES (CONTINUED)
- THE TORC COMPUTER CODE WAS USED TO CALCULATE MINIMUM DNBR AS OPPOSED TO THE CETOP CODE USED FOR THE AMENDMENT H ANALYSIS l
.i O
IMPACT ON RESULTS l
- DNBR AND FUEL FAILURE IMPROVES DUE TO ROPM, COIL DECAY TIME, MTC, AND USE OF THE TORC COMPUTER CODE
- PEAK RCS PRESSURE REDUCED DUE TO LOWER INITIAL PRESSURIZER PRESSURE, MTC, AND COLD LEG TEMPERATURE
- PEAK SG PRESSURE REDUCED DUE'TO REDUCTION IN COLD l
LEG TEMPERATURE
- DOSE IS REDUCED DUE TO REDUCED FUEL FAILURE; AFFECTED BY SG INVENTORY
{
AMENDMENT H AMENDMENT N MINIMUM DNBR 0.83 1.09 FUEL FAILURE 3.5%
1.2%
l PEAK RCS PRESSURE 2647 PSIA 2615 PSIA PEAK SG PRESSURE 1276 PSIA 1248 PSIA 2 HOUR THYROID DOSE 18.1 REM 2.9 REM j
i 4
9 I
l
.e 15.4.1 UNCONTROLLED CEA WITHDRAWAL FROM SUBCRITICAL OR LOW POWER CONDITIONS l
O EVENT DEFINITION CHANGE
- ZERO TIME. DELAY'ON LOSS OF OFFSITE POWER
- LOSS OF-OFFSITE. POWER CONSIDERED AS PART OF. THE
~i EVENT (NO RECATEGORIZATION)
O SIGNIFICANT ANALYSIS CHANGES
- MODERATOR-TEMPERATURE COEFFICIENT DECREASED FROM
+0. 5 X 10-* DELTA-RHO / F (AMENDMENT H) TO 0.0 (AMENDMENT N)
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N)
O IMPACT ON RESULTS
- DNBR INCREASED DUE TO REDUCTION IN MTC AND COIL DECAY TIME
-l AMENDMENT H AMENDMENT N f
MINIMUM DNBR 2.26 3.71
, t h
i
?
-f
15.4.2 UNCONTROLLED CEA WITHDRAWAL AT POWER O
EVEW_' DEFINITION CHA.NGE
- ZERO TIME DELAY ON LOSS OF OFFSITE POWER
- LOSS OF OFFSITE POWER CONSIDERED AS PART OF THE EVENT (NO RECATEGORIZATION)
O SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASED
- INITIAL DNBR INCREASED FROM 1.51 (AMENDMENT H) TO 1.62 (AMENDMENT N)
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N)
I O
IMPACT ON RESULTS
- ROPM AND DECREASED COIL DECAY TIME INCREASES DNBR; LOSS OF OFFSITE POWER DECREASES DNBR:
NET CHANGE IS SMALL AMENDMENT H AMENDMENT N MINIMUM DNBR 1.32 1.33 F
t l
P l
15.4.3
.{
SINGLE CEA DROP
{
)
O EVENT DEFINITION CHANGE l
]
- ZERO TIME DELAY ON LOSS OF OFFSITE POWER
- LOSS OF OFFSITE POWER CONSIDERED AS PART.OF THE I
EVENT (NO RECATEGORIZATION) l O
SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASED i
INITIAL DNBR INCREASED FROM 1.58 (AMENDMENT H) TO' 1.62 (AMENDMENT N)
L
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N)
- AMENDMENT H ANALYSIS CHOSE AN INITIAL DNBR SUCH THAT THE RESULTING TRANSIENT MINIMUM DNBR WAS 1.24 1
O IMPACT ON RESULTS
- ROPM, DECREASED COIL DECAY TIME, AND METHODOLOGY CHANGE INCREASES DNBR; LOSS OF OFFSITE POWER i
DECREASES DNBR:
NET INCREASE IN DNBR j
.MENDMENT H AMENDMENT N MINIMUM DNBR 1.24 1.35 i
l
i 15.4.6 i
INADVERTENT DEBORATION O
EVENT DEFINITION CHANGE
- NO CHANGE t
O SIGNIFICANT ANALYSIS CHANGES
- AMENDMENT N ANALYSIS UTILIZES THE BORON DILUTION ALARM IN MODES 3-6; THE MAKEUP WATER FLOW. ALARM IS f
A BACKUP IN MODE 6.
AMENDMENT H ANALYSIS i
UTILIZED.A COMBINATION OF THE BORON DILUTION AND MAKEUP WATER FLOW ALARMS i
- THE SHUTDOWN MARGIN WAS INCREASED TO 5.75%
(AMENMDMENT N) FOR MODE 5 IN THE DRAINED CONDITION.
THE AMENDMENT H ANALYSIS USED 3%
- THE VOLUME OF WATER IN THE SHUTDOWN COOLING SYSTEM WAS REDUCED FOR THE AMENDMENT N ANALYSIS
- THE CHARGING. FLOW OF 180 GPM (AMENDMENT H) WAS REDUCED TO 160 GPM (AMENDMENT N)
O IMPACT ON RESULTS i
AMENDMENT H AMENDMENT N TIME TO REACH CRITICALITY 38 MINUTES 67 MINUTES 9
r i
i i
I
II 1
y i
15.4.8 f
3 CEA EJECTION l
.i O
EVENT DEFINITION CHANGE l
- ZERO TIME DELAY ON LOSS OF OFFSITE POWER t
O SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASED i
COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5
.c (AMENDMENT N) l
- CORE AVERAGE. LINEAR HEAT GENERATION RATE IS LOWER FOR THE 3992 MWT DESIGN AS COMPARED TO THE 3800 MWT DESIGN DUE TO THE ADDITION OF INTEGRAL BUPNABLE l
POISON
- 3% POWER INCREASE IMPACTS PEAK PRESSURE l
- PRESSURIZER PRESSURE 2400' PSIA (AMENDMENT H)
REDUCED TO 2325 PSIA (AMENDMENT N) FOR PEAK PRESSURE CASE
- PSV LIFT PRESSURE UNCERTAINTY INCREASED FROM 25 PSI (AMENDMENT H) TO 40 PSI (AMENDMENT N)
- THE FULL POWER MODERATOR TRMPERATURE COEFFICIENT j
HAS CHANGED FROM 0.0 (AMENDMENT H) TO - 0.1 X 10-4 DELTA-RHO / F (AMENDMENT N) i
- METHODOLOGY CHANGED FOR COMPUTING OFFSITE DOSES
- NUREG-1465 SOURCE TERM t
- EPRI X/Qs i
i I
i 15.4.8 J
CEA EJECTION i
I (CONTINUED)
O IMPACT ON RESULTS l
- ROPM, DECREASED COIL DECAY TIME, AND NEGATIVE MTC REDUCE AMOUNT OF FUEL FAILURE
- PEAK RCS PRESSURE DECREASES DUE TO LOWER INITIAL PRESSURE; INCREASED PSV OPENING SETPOINT AND POWER LEVEL AFFECT FINAL RESULT
- DOSES INCREASE DUE TO METHODOLOGY CHANGE AMENDMENT H AMENDMENT N FUEL FAILURE
< 10% (6. 8%)
4.4%
PEAK RCS PRESSURE 2742 PSIA 2733 PSIA 2 HOUR THYROID DOSE 2.95 REM 69.6 REM i
i f
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t t
15.5.2 PLCS MALFUNCTION O
EVENT DEFINITION CHANGE
- ZERO TIME DELAY FOR LOSS OF OFFSITE POWER
- LOSS OF OFFSITE POWER CONSIDERED AS PART OF THE EVENT (NO RECATEGORIZATION)
O SIGNIFICANT ANALYSIS CHANGES
- ROPM INCREASED
- INITIAL DNBR INCREASED FROM 1.57 (AMENDMENT H) TO 1.62 (AMENDMENT N)
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMNET H) TO 0.5 SEC (AMENDMENT N)
- 3% POWER UPGRADE IMPACTS PEAK RCS AND'SG PRESSURES
- PSV LIFT PRESSURE UNCERTAINTY INCREASED FROM 25 PSI (AMENDMENT H) TO 40 PSI (AMENDMENT N)
O IMPACT ON RESULTS
- DNBR INCRRASES DUE TO ROPM
- PEAK RCS PRESSURE INCREASES DUE TO INCREASED POWER AND PSV LIFT PRESSURE
- PEAK SG PRESSURE INCREASES DUE TO INCREASED POWER AMENDMENT H AMENDMENT N MINIMUM DNBR 1.57 (INITIAL) 1.62 (INITIAL)
PEAK RCS PRESSURE 2639 PSIA 2682 PSIA PEAK SG PRESSURE 1247 PSIA 1266 PSIA
i 15.6.2 LETDOWN LINE BREAK O
EVENT DEFINITION CHANGE
- LETDOWN LINE BREAK WITH LOSS OF OFFSITE POWER O
SIGNIFICANT ANALYSlS CHANGES
- MINIMUM DNBR FOR STEAM GENERATOR TUBE RUPTURE BOUNDS LETDOWN LINE BREAK:
HIGHER AVERAGE MASS FLOW RATE OUT THE BREAK FOR A TUBE RUPTURE
- DECONTAMINATION FACTOR IN THE NUCLEAR ANNEX REDUCED FROM 3 (AMENDMENT H) TO 1 (AMENDMENT N)
- SYSTEM 80+ LETDOWN LINE MODEL USED RATHER THAN SYSTEM 80 i
SYSTEM 80+ ORIFICES CREDITED SYSTEM 80+ LETDOWN HEAT EXCHANGER IN l
CONTAINMENT CREDITED l
- LOWER INITIAL RCS PRESSURE BY 50 PSI
- LOWER INITIAL COLD LEG TEMPERATURE BY 2 F
- EPRI X/Qs O
IMPACT ON RESULTS
- LOWER INTEGRATED MASS RELEASE AND FLASHING FRACTION ENABLES DOSE ACCEPTANCE CRITERION TO BE MET CONSIDERING LOWER DF AND INCREASED X/Qs
s t.
15.6.2 i
LETDOWN LINE BREAK (CONTINUED)
?
j
.e AMENDMENT H AMENDMENT N i
MASS RELEASE OUT BREAK 107442 LBS 48617 LBS FLASHING FRACTION 40.0 %
19.8 %
i 2 HOUR THYROID DOSE 22.O REM 26.7 REM b
I
[
l I
I L
'8 i
15.6.3 STEAM GENERATOR TUBE RUPTURE
.(
i O
EVENT DEFINITION CHANGE
- ZERO TIME DELAY FOR LOSS OF OFFSITE POWER r
I O
SIGNIFICANT ANALYSIS CHANGES
- POWER INCREASE OF 3 %:
IMPACTS DOSE
- ROPM INCREASE
- INITIAL DNBR INCREASED FROM 1.53 (AMENDMENT H) TO 1.68 (AMENDMENT N)
- COIL DECAY TIME FOR SCRAM RODS DECREASED FROM 0.8 SEC (AMENDMENT H) TO 0.5 SEC (AMENDMENT N)
- NEW CPC TRIP ALGORITHM:
COINCIDENT LOW PRESSURE LOW DNBR
- EPRI URD X/Qs O
IMPACT ON RESULTS
- FUEL FAILURE IS PREVENTED VIA NEW CPC TRIP ALGORITHM
- DOSES INCREASE DUE TO INCREASED STEAM RELEASE DUE TO DECAY HEAT AND INCREASED X/Qs AMENDMENT H AMENDMENT N TWO HOUR THYROID DOSE 44.9 REM 93.1 REM (LIMITING DOSE)
I
r Ouestion 440.220:
In the I&C. diversity analysis, the moderator and Doppler reactivity feedback functions are the main parameters to control the core power increase or decrease in the events analyzed.
Provide the values of the moderator and Doppler reactivity coefficients assumed in the analysis.and justify the adequacy of these values for each event analyzed.
P i
Response 440.220:
The values assumed for the moderator and Doppler. reactivity coefficients / functions in the I&C diversity analysis are provided in the attached tables.
Also provided is the justification for the use of the coefficients for individual events analyzed.
i t
k I
6 t
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TABLE 440.220-1 EVENT MODERATOR JUSTIFICA-DOPPLER JUSTIFICA-TEMPERATURE TION OF MTC TEMPERATURE TION OF DTC COEFFICENT VALUE COEFFICIENT VALUE
( d P /9P)
(MULTIPLIER) 4 LOSS OF FLOW
-1.8X10 MEDIAN VAL,UE LEAST MOST NEGATIVE CONSERVATIVE (1.0)
(WITHOUT UNCERTAINTY) 4 LOCKED ROTOR /
-0.1X10 MOST LEAST MOST SHEARED SHAFT POSITIVE NEGATIVE CONSERVATIVE (0.85)
(WITH UNCERTAINTY) 4 CEA EJECTION
-1.8X10 MEDIAN VALUE LEAST MOST NEGATIVE CONSERVATIVE (1.0)
(WITHOUT UNCERTAINTY)
LETDOWN LINE DNBR BOUNDED BY SGTR BREAK SGTR 0.0 REPRESENTA-MOST NEGATIVE REPRESENTA-TIVE VALUE:
(1.38)
TIVE VALUE:
MARGINAL MARGINAL IMPACT IMPACT STEAM LINE FIG.
EXTREMELY MOST NEGATIVE MOST BREAK 15.1.5-0 CONSERVATIVE (1.38)
CONSERVATIVE 4
MTC=-5.4X10 (WITH t1 (2 / F UNCERTAINTY)
FEEDWATER LINE 0.0 MOST LEAST MOST BREAK POSITIVE NEGATIVE CONSERVATIVE (1.0)
(WITHOUT UNCERTAINTY)
LOCA SEE TABLE BE*-H FP MOST NEGATIVE MOST 440.220-2 MODERATOR (1.0)
CONSERVATIVE DENSITY VS.
(WITHOUT REACTIVITY UNCERTAINTY)
(TABLE 2)
- Best Estimate
TABLE 440.220-2 l
CORE AVERAGE REACTIVITY 3
DENSITY (LBM/FT )
(/1G) 27.00000
-0.044248 28.00000
-0.038829 29.00000
-0.033939 30.00000
-0.029527 31.00000
-0.025552 l
32.00000
-0.021972 33.00000
-0.018755 34.00000
-0.015867 35.00000
-0.013283 36.00000
-0.010977 37.00000
-0.008928 38.00000
-0.007116 39.00000
-0.005523 40.00000
-0.004135 41.00000
-0.002935 42.00000
-0.001911 43.00000
-0.001049 44.00000
-0.000335 45.00000 0.000245 46.00000 0.000704 47.00000 0.001059 48.00000 0.001325 49.00000 0.001522
+
50.00000 0.001671 I
Question 440.221 The design RCS flow, as stated in Chapter 15 of CESSAR-DC, is 445,600 gpm.
The vessel flow is assumed to be 461,200 gpm in
~
the analysis.
Clarify the difference in flow rates and revise, if necessary, the analysis to reflect the correct flow rate consistent with the best estimate method proposed in the analysis.
Response 440.221 1,q1 I
q The actual best esJimate flow rate for the System 80+ plant ranges between A d,099 gpm and 480,211 gpm.
These flow rates were computed based on best estimate system resistances and reactor coolant pump performance.
The 461,200 gpm flow rate was chosen in order to be somewhat higher than the Chapter 15 value, since the flow rate expected to be seen at an actual plant is normally higher than that stated in Chapter 15.
The 461,200 gpm is approximately the average between 445,600 gpm and the minimum best estimate flow rate of 477,099 gpm.
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Ouestion 440.222:
To be consistent with the operator action analysis in Section 2.4, the RCP trip delay time is assumed to be 23 minutes after the 6" IpCA initiation (page 75).
For the SBLOCAs of 3" and-O.041 ft breaks, the RCPs are tripped much sooner (17 minutes following the LOCAs stated in pages 75 and 75).
Clarify the discrepancy in the RCP trip times assured in the SBLOCAs.
Response 440.222:
The estimate of reactor operator response described on page 74 indicates that the operator could be reasonably expected to trip two RCPs within 16 minutes and two more within 22 minutes.
These times for operator action are consistent with the so-called " Trip 2 Leave 2" (T2/L2) RCP trip procedure and represent the best guess at the appropriate times for tripping the RCPs.
As described on page 74, the RCP trip delay time of 23 minutes for the 6"
break in the top of the pressurizer was not selected to be consistent with the T2/L2 operator action analysis but to be conservative. As stated on page 74, it was found to be conservative for this break in the pressurizer to delay RCP trip.
Therefore, it was assumed that all four RCPs were tripped 23 minutes after event initiation.
This time is one minute beyond the time for reasonable operator completion of the T2/L2 procedure.
As described on page 75, the RCP trip delay time of 17 minutes for the 3"
break in the top of the cold leg was also not selected to be consistent with the T2/L2 operator action analysis but to be conservative.
Early RCP trip w&s found to i
be conservative for this break in the cold leg.
Therefore, it was assumed that all four RCPs were tripped 17 ninutes after event initiation.
this time is one minute after the time of assumed HPSI actuation and accounts for early recognition by the operator of the need to trip all RCPs during the LOCA event.
As described on ppge 76, the RCP trip delay time of 17 minutes for the 0.041 ft break in the top of the vessel upper head was selected.
The calculated response for this event is relatively insensitive to the RCP trip sequence due to the break size and location.
Parametric calculations for both trip sequences produced the same results for this event.
i I
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Ouestion 440.223:
It is stated in the conclusion of the SBLOCAs (page 77) that no core uncovery is calculated for the cases analyzed.
Figure 3.8-21 shows that for 3" break LOCA, the collapsed water level falls up to 4 feet below the top of fuel for about 60 seconds.
Clarify the inconsistency of the core covery in your j
conclusion and Figure 3.8-21, and demonstrate that the core 1
coolability can be maintained for the 3" break case.
L Response 440.223:
The occurrence of core uncovery is based on the calculated two-phase mixture level in the inner vessel node not on the collapsed liquid level.
Refer to Figure 3.8-20 (actually mislabeled as 3.9-20 in the report) for the mixture level versus time graph.
The collapsed liquid level graph is usually included in the results so that it can be compared to the two-phase mixture level graph.
This comparison shows the void fraction in the core two-phase region or the extent of core boiling or steam production being calculated during the transient. The collapsed liquid level is a hypothetical level based on instantaneously releasing all the steam from the two-phase region and therefore does not indicate any true level of uncovery.
I
?
i Question 440.226 5
The applicant is requested to discuss indications and controls utilized to respond to events and their diversity rationale (including the normal instrumentation and control systems).
The discussion should cover each event presented in the report included in an ABB-CE letter, LD-93-083, and its References 2 and 6.
l Response 440.226
^
Section 1.0 of ALWR-IC-DCTR-31 discusses the allocation of diverse software to the I&C equipment used for protection, control, and information displays in NUPLEX 80+.
Diverse equipment, as discussed in Section 3.0 of ALWR-IC-DCTR-31, use diverse microprocessors, and diverse operating systems in the microprocessors, and the applications software is developed by l
independent teams.
The control and information display equipment which - remain available with the postulated common mode software failure are identified in Section 2.0 of ALWR-IC-DCTR-31.
The implications of the common mode failure on the normal plant l
response and the indications and controls which remain l
available for coping are presented for each event in Section 4 of ALWR-IC-DCTR-31.
e i
Discussions with the NRC staff subsequent to the Lawrence Livermoore review of the ALWR-IC-DCTR-31 evaluation determined that the capability of the diverse equipment to provide adequate protection had been demonstrated for 19 of the 28 event initiators in Chapter 15.
Subsequent discussion of the evaluation with NRC management determined that a revised evaluation would be appropriate for the remaining 9 events, and would apply more relaxed criteria than those applied in Chr.pter 15 and credit use of manual controls implemented in j
the design to comply with position 4 of the NRC policy i
statement on common mode failure.
In Section 2.2 of the revised evaluation (LD-93-083),
a more detailed description is provided of the instrumentation available to the operator.
In Section 2.3 of LD-93-083, the specific information available to support credited operator actions is identified for each of the 9 events.
. ~
i i
i Ouestion 440.227 I
i It is indicted in Section 2.3, the determination of the required event diagnostic time of one minute is based on ATWS scenarios.
According to CE-EPGs, the ATWS event diagnosis requires verification on the post-trip rod position as the sole diagnostic step.
However, a common mode failure (CMF) event involves more complications which include conflicting indications and inoperable controls in combination with a plant transient.
The applicant is requested to provide bases that justify the response time of one minute as sufficient for the CMF event diagnosis.
Response 440.227 f
In discussing operator initiation of a manual reactor trip, Section 2.3 of LD-93-083 reports that the data discussed in the Appendix to ANS-58.8 and in Reference 8 of LD-93-083 j
indicate that, in the response time data determined for ATWS i
scenarios, the earliest time for operator action is typically less than 1 minute.
The discussion in Section 2.3 goes on to identify the specific indications available to the operator to prompt his manual initiation of a reactor trip.
The multiple familiar indications provided to the operator of the need for a reactor trip, the availability of the DIAS-P indications to i
confirm that a trip had not occurred and the empirical response data for ATWS scenarios provide the basis for concluding that operator action to initiate a manual reactor trip within two minutes of reaching an alarmed trip condition is considered reasonable for the purposes of the beyond design basis analysis provided in LD-93-083.
Section 2.3 of LD-93-083 also discusses the bases for response times considered reasonable for operator actions performed as part of the Standard Post-Trip Actions, i.e.,
subsequent *,o a reactor trip initiated manually or by the Alternate Protection j
System.
That discussion identifies that if a step in the EPG involves simple verification of parameters which are readily available on a normal DPS display and'can be verified on DIAS-P, and the value can be expected to be within the acceptable range, then that step in the EPG is estimated to take 1 minute per manipulation, which is consistent with the ANS-58.8 model for performing familiar actions.
Additional time was allocated in the response time estimates for indications which could not be readily verified and for j
actions for which the normal control interface was assumed inoperable.
During the first nine minutes of the response sequence, four minutes are allocated for the supervisor and two operators to identify that a global problem has occurred in the DIAS-N displays and to determine that the DPS displays
Fesponse 440.227 (continued) should be used ad.
This is reasonable since there will be multiple al" provided by the DPS displays and IPSO
(
indicating a s3..ticant plant problem, and the condition could be confirmed via the DIAS-P displays.
Since the DPS would alarm discrepancies between parameter values validated independently by the DPS and DIAS, and since the DIAS-N implements a different type of display device than used by the-t DPS and each DIAS-N and DPS display panel displays a rotating icon to indicate if the information on the screen is being
- updated, a
system wide DIAS-N failure would be readily evident.
For actions for which the normal control interface would be inoperable, e.g. for ESF equipment actuation, additional time was allocated for the operator to determine that the manual initiation had not taken effect and then to perform manual initiation using the diverse manual actuation switches.
I L
T f
i f
f 2
/
r
Ouestion 440.228 The applicant is requested to confirm that CE-EPGs are adequate to guide operators for response to CMF events.
If the applicant finds that the EPGs revision is necessary for the CMF event mitigation, the revised EPGs should be provided for the staff to review.
r Response 440.228 The EPGs do not need to be revised to support the assumptions made for operator responses in the LD-93-083 evaluation.
The EPGs specify the parameters or information the operator is to use to establish the status of critical functions, and they specify the system or component responses to be actuated if required.
The DPS provides alarms to indicate when discrepancies are found between parameter values validated by the DPS and those validated independently by DIAS.
The evaluation assumes that the operators will have guidance to use the DIAS-P displays to verify either DIAS-N or DPS indications under circumstances where they are inconsistent, and to use the diverse manual actuation switches if they are unable to establish that successful actuation of the i
associated equipment has occurred when using the ESF-CCS.
The LD-93-083 evaluation demonstrates that the implementation of diversity in System 80+ is sufficiently comprehensive for coping with common mode failures, that even if a failure were postulated to disable all of the protective functions normally performed by the
- PPS, the ESF-CCS and the monitoring capability of the DIAS; the plant would retain a sufficient combination of automatic
- controls, manual controls and indications to provide adequate protection even for low probability limiting fault events.
ABB-CE does not consider such a scenario to be credible and, therefore, does not consider it appropriate as a design basis for the plant protective systems.
Other aspects of the NUPLEX 80+ design assure the reliability of the protective systems and the extremely low probability of an impairment of their protective functions by any common mode failure.
Most important among these is the emphasis on simplicity in the digital technology used for protective function actuation and control and the rigor of the verification and validation process.
- However, metrics are not currently available in the industry to quantify the benefit of this approach.
Therefore, the LD 083 evaluation was performed as a demonstration of the extensive protection provided by the implementation of diversity in System 80+.
Consideration of the other aspects of the NUPLEX 80+
- design, in combination with this demonstration of the extensive benefit provided by diversity establishes the acceptability of the NUPLEX 80+ design for j
addressing the potential impact of common mode software failures.
I
Question 440.209:
"In the analysis, the AFW is actuated on the low SG water level signal when the automatic mode is assumed.
In the SGTR analysis when the high SG water level trip signal is credited for the reactor trip.
As stated in Information Notice 92-54, the water level instruments are subject to significant errors.
The applicant is requested to provide. an assessment 'of the effects of level instrumentation errors on the safety analysis results, which rely on the level instruments for accident mitigation."
Response 440.209:
USNRC Information Notice 92-54 discusses possible PWR pressurizer level inaccuracies caused by the degassing of the l
reference leg during rapid system depressurizations.
Non-condensible gases that are added to the primary coolant for chemistry control (e.g., hydrogen) may come out of solution in the pressurizer, migrate to the reference leg via the condensing pot and then diffuse into the reference leg. These dissolved gases may then displace the reference leg water as the gas expands and rises during a
rapid system depressurization.
This would cause the pressurizer level instrumentation to give an inaccurate- (high) reading.
The steam generator level instrumentation is much less likely to experience this phenomena because of the lack of significant quantities of dissolved gases in the feedwater (see CESSAR-DC Table 10.3.5-1) and the absence of rapid depressurizations in the steam generators.
The only dissolved gas in the feedwater is oxygen at a very low concentration (see CESSAR-DC, Table 10.3.5-2).
The high steam velocities in the steam generator would make oxygen retention (and eventual migration and diffusion into the reference leg) highly unlikely.
The reactor trip that occurs during the early part of the natural circulation cooldown will result in a high secondary pressure which would not cause a degassing of the reference leg.
Later in the event, the steam generator pressure is reduced corresponding to a plant cooldown rate of 50 degrees F/hr.
Such a relatively slow reduction in secondary pressure would not cause steam generator level errors associated with liquid displacement from the reference leg.
i
Ouestion 440.197 Provide the revised TSs that reflect the assumptions and results of Chapters 6 and 15 reanalysis.
Response 440.197 The System 80+" Technical Specifications have been updated to reflect adjustments resulting from the revised safety analysis.
These updates primarily involved adjustments to LCOs rather than changes which affected a fundamental basis for having the Technical Specification. As a general rule, numerical values stated for LCOs in the Technical Specification are i
representative of the values that would appear in a site specific set of Technical Specifications. This is indicated in the CESSAR DC Chapter 16 Technical Specifications by placing a bracket around such values or conditions.
The actual values that would be included in a Licensee's Technical Specifications would reflect the specific equipment procured and installed, uncertainties for instrumentation, calibration, equipment uncertainties, among others. The attached Table 440.197-1 provides a list of the Technical Specifications that were revised to reflect Chapters 6 and 15 reanalyses. These changes will be implemented in the next revision to CESSAR-DC.
p e
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o TABLE 440.197-1 CESSAR-DC Technical Specification LC0 Paranraph No.
Parameter Old New Source LCO 3.1.4 Moderator Temperature 0.0x10
-0.1x10~4 Table 15.3.1-2
-4 Coefficjent-IIFP
( A Q / F)
LCO 3.1.11 Number of Charging Pumps 2
1 Section 15.4.6 Operating LC0 3.4.1 a.)
Pressurizer 1905-2175-Table 15.0-3 Pressure Range (psia) 2375 2325 T
R nge ( F):
cold LCO 3.4.1 b.)
< 90% Power 543-543-Table 15.0-3 565 561 LC0 3.4.1 b.)
90%-100% Power 553-550-Table 15.0-3 563 561 Rx Trio Setpoints:
LC0 3.3.1 liigh Pressurizer Pressure (psia) 2445 2434 Table 15.0-3 2015 Table 15.0-3 LOC 0 3.3.5 CPC Coincident Low Pressure /DNBR (psia)
Table 15.0-3 LCO 3.4.3 RCS P-T
- Limits
- NOTE: The RCS Pressure and Temperature Limit Curves were revised to reflect the 3% power increase and the initial condition space.
O Ouestion 440.198:
Figures 6.3.3.2-11 and 6.3.3.3-12 Prwide the results of sensitivity study for the break size spectnn to shw that the lpiting cases are the DEG/PD for large break IDCAs and the break of 0.1 ft for small break IOCAs.
Ty s;vis.e 440.198:
2 e results of sensitivity studies that demonstrate that the limiti p G IJDCA is the 1.0 DEG/PD break ard the limitirg SB IDCA is the 0.1 ft Un line break are sh wn in Figures 6.3.3.2-11 ard 6.3.3.3-12.
As sh wn in Figure 6.3.3.2-11, the break size spectnn analysis perforned at 3876 Et identified the 1.0 DIX;/PD break as the limiting break for the System 80+ LB IDCA analysis.
De limiting IB IDCA break size is detemined by the therral-hydraulic response of the core during the blowdsn portion of the LB IDCA transient. The differences in the System 80+ design is going from 3876 MYt to 3992 Et do not charge the therral-hydraulic response of the core sufficiently to cause a charge in the limiting break size. E is is sh wn by a carparison of CESSAR-DC Figures 6.3.3.2-5A through SE to Figures 6.3.3.2-10A through 10E. W erefore, the 1.0 DD3/PD break is also the limiting G IDCA at 3992 Et.
As shwn in Figure 6.3.3.3-12, the break size spch analysis performed at 3876 Et identified the D'E line as the limitire break location for the System BM SB IDCA analysis.
Se rajor reason the UH line is the limitirg break location is that, in conjunction with a diesel generator failure, it results in the minimum arount of SI ptrp flow reaching the core (100% of the flw fram one SI pxp). For a break in the RCS hot or cold legs, 100% of the flow from two SI pxps reaches the core.
(See CESSAR-DC Section 6.3.3.3.2).
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Eree UH line breaks (0.05 ft, and 0.1 ft ) were analyzed at a core pwer of 3992 Et in order to determine the limi, ting break size.
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limiting break size was determined to be the 0.1 ft break. Breaks larger 2
2 than 0.1 ft are less limitire than the 0.1 ft break because they are large enough such that the RCS will depressurize to the point that SITS cane on and reflood the core before the peak cladding taperature can 2
exceed that calculated for the 0.1 ft break.
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Oocstion 440.199:
Table 6.3.3.2-2 hty the core ard the RCS flow rates are assuned to be the sane?
Response 440.199:
the core ard RCS fim rates are not the sare in Table 6.3.3.2-2.
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exa ple, the initial RCS flw rate is 165.8x10 16/hr for the analysis at 3992 E't.
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3 Ouestion 440.200:
Tables 6.3.3.2-2 and 6.3.3.3-2 k'hy the initial core outlet terperatures are different for IB and SB IDCAs?
i Resporm 440.200:
the IB IOCA blowdcrm analysis explicitly rodels core bypass flw, khereas, the SB LOCA blowdwn analysis does not.
Consegaently, the initial core outlet teqperature listed in Table 6.3.3.2-2 for IB IDCA is based on the 6
actual core flw rate of 160.8x10 lb yhr while the initial core outlet te."pcrature listep in Table 6.3.3.3-2 for SB LOCA is based on the RCS flw j
rate of 165.8x10 lbWhr.
Since the SB IDCA blowdwn analysis uses a j
higher initial core flw rate (and has the same initial core pwer and inlet terperature), it has a I wer initial core outlet terperature.
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Ouestion 440.201:
Table 6.3.3.3-2 What is the limiting burnup resulting in a highest PCI for SB IDCAs?
RczTx. scc 440.201:
As prescribed on page 18 of CDIPD-137P, " Calculative Methods for the C-E Small Break IDCA Evaluation Model," August 1974 (Reference 3 of Section 5.3.3 of CESSAR-DC), the SB IDCA analysis is performed for the burnup "at which the initial stored energy in the fuel is highest." For the CESSAR-DC SB 10CA analysis, this corresponis to a hot rod burnup of 1000 MO/MIU.
Furthennore, the peak cladding terperature for the limiting SB IDCA is driven by decay heat and is not sensitive to the initial stored energy in the fuel.
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Question 440.202:
Assunption I, page 6.3-35 Provide the basis for the boric acid precipitation of 27.6% at the contain:nent pressure of 14.7 psia.
Response 440.002:
'Ihe boric acid precipitation of 27.6 wt% at a pressure of 14.7 psia was obtained frorn Figure C-3, page 4, A~eJKhaent 1 of CENPD-254-P-A, " Post-LOCA Ieng Term Cooling Evaluation Model," June 1980 (Reference 9 of Section 6.3.3 of CESSAR-EC).
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1 OtKLstion 440.203:
Table 6.3.3.4-1 Provide an explanation for the reaning of the note for SCS entry conditions (tenperature ard pressure) with consideration of the associated
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instrunentation errors.
Resconse 440.203:
'Ibe values of 360 F ard 330 psia are the rdninrn values for the actual hot leg to:"perature and pressurizer pressure, respectively, when the control roon instrumentation is indicating the raxinzn allowable post-accident values for entry into shutdcun cooling, namely, 380 F aid 400 psia. 'Ihe values of 360 F and 330 psia are based on post-accident instrument errors of 120 F ard 170 psi, respectively.
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Qxstion 440.204:
Figure 6.3.3.4-5 Provide analytical results to show that for srall break IDCAs with break 2
sizes smaller than 0.01 ft, the SCS entry conditions can be achieved in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> to support the resolution of Open Itcas 6.3.3-1 (see C-E letter, ID-93-048, dated Mart:h 17, 1993).
Ecsponse 440.204:
As part of the post-IDCA long term cooling analysis that is described in Section 6.3.3.4 of CESSAR-DC, the NATFICH ard CEPAC canputer programs are used to calcuhte a natural circulation cooldown of the RCS.
It is calculated to determine the earliest time that the SCS entry temperature is reached following a ID :A. We analysis simulates a conservatively slow cooldown rate and, consequently, a raximum value for the earliest time that the SCS engry temerature is reached.
For exagle, the analysis assunes a 0.0 ft break size (i.e., no RCS energy goes out the break; it is all renoved via the steam generators) and that only one atrospheric dump valve per steam generator is available.
Also, steam generator cooldown is assuned to begin 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after the start of the IOCA.
Te natural circulation cooldom analysis deterrined that the SCS entry ETerature of 360 F is reached at approxirately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after the start of the IDCA.
(As stated in the response to Question 440.203, 360 F corresponds to the rtinitum actual hot leg terperature when the irdicated hot leg temperature is 380 F, the raxinrn allcsable indicated post-accident hot leg te@erature for entry into shutdown cooling.) 'Iberefore, the analysis deronstrates that the SCS entry tenperature can be achieved well before 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> after the start of a IDCA. In addition, reaching the SCS entry terperature at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> leaves agle time for the operator to depressurize the RCS to the SCS entry pressure ard initiate shutdown cooling.
r-Ouestion 440.205:
RCS Flw Rates the design RCS flw rate is 444,650 grm stated in Table 4.4-1.
'Ibe design RCS flw used for the transient analysis is 446,600 gpm as stated in Table 15.0-3.
Clarify this discrepancy and revise t he transient reanalysis reflecting the correct RCS f1w rate.
Resocnse 440.205:
Table 15.0-3 identifies a range of reactor vessel flows to be used for initial conditions for the safety analyses. the flows range fmn 423,320 gpm to 516,896 gpm or approximately 95% to 116% of the design floWTate of 444,650 gpm. since the design RCS flw rate falls well within the rarge considered in the safety analyses, there Is no discrepancy.
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Ouestion 440.206:
me initial des for the transients are significantly higher for the reanalyzed cases than that of existing cases.
For exanple, the initial DE for the inadvertent openirg of a SG AW increased from 1.24 to 1.36, stile the rated pwer increased fram 3800 to 3914 MRt and the raximum radial peakirg factor increased from 1.4 to 1.44 (Table 15.1.4-3), stich could decrease the initial DE. Se applicant is reqaired to provide the technical basis for the significant increase in initial DERs for all the events reanalyzed.
Response 440.206:
i ne initial DERs for the System 80+ pwer upgrade reanalysis are higher than those of the original analyses (Arendnent H) due to a change in the overpmer rargin reserved for the analyses.
This Required Overpwer Margin (ROR4) represents the distance, in units of pwer, from the specified acceptable fuel design limit (SAFDL). A higher ROR4 results in an initial DER that is further from the SAFDL and is thus higher.
l me DERs stated in the question for the Inadvertent Opcning of a Steam i
Generator Atmospheric Dump Valve (ISOGAW) event are not the initial DERs but are the DERs at 30 minutes into the event.
H e reason these two DERs are different is that a change in the approach used to select the initial conditions was applied for the reanalysis.
In the original analysis a DER of 1.24 was forced to occur at 30 minutes as this was the minin:m DER which could occur prior to a CPC reactor trip. This approach is overly conservative since the initial thermal rargin khich would need to be assumed for the DE to be 1.24 at 30 minutes vould be less than that reserved by the ROR4.
mat is, the plant would have to have been operating in violation of a Pwer Operating Lirit (POL) prior to event initiation (see the response to FAI 440.215). he reanalysis assel the plant to be initially (time =0) operatirg at a ICL.
'Ihis resulted in a DER of 1.36 at 30 minutes into the event.
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Ouestions 440.207:
Page 15.1-18 The control rcd worth of 10% was used in the SLB analysis.
This value is significant increassd (from 8.86%).
Provide the basis for the increase.
Clarify that whether the change is due to the control rod design change or the calculational method change for the control rod worth.
Response 440.207:
The change in CEA worth used in the steam line break (SLB) analyses from 8.86 %4/ to 10 %4/ results from an analysis of the apportionment of conservative margins to the values of the reactivity components of the SLB analyses for potential post-trip return to power.
Figure 15.1.5-0 of CESSAR-DC is useful in understanding this.
As a reference point, a CEA Worth of 10
% A[ used together with the moderator cooldown function represented by the lower curve of Figure 15.1.5-0 results in post-trip reactivity values which are typical of those appropriate to SLB analyses (assuming the usual conservatisms such as end of fuel cycle).
Either decreasing the CEA worth used together with this curve or using a CEA worth of 10 %g together with a more adverse (more negative slope) curve will increase the conservatism of the analysis results.
The CEA worth of 10 % 4f used together with the moderator cooldown function employed in the SLB analyses for CESSAR-DC (upper curve of Figure 15.1.5-0) yields results which are appreciably more conservative than the most adverse expected for System 80+.
Employing both a value of 8.86 U/ CEA worth and the upper curve would produce an extreme, excessively conservative bound for the expected post-trip reactivity change.
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Ouestion 440.208:
i Page 15.1-15 The staff agrees that an early actuation of the AFW will maximize the cooldown effeet and is a conservative assumption for the post-trip SLB analysis.
For an SLB with a loss of I
offsite power assuming failure of an MSIV in the intact SG to close, a delay of AFW actuation could result in a complete depletion of the water inventory from both SGs.
Under this condition, the injection of cold AFW could cause significant thermal stress on SGs and result in a further damage to SGs.
The applicant is requested to provide an analysis showing that a delay of AFW actuation (such as AFW on an automatic mode) will not result in a complete depletion of inventory from both l
SGs and a complete loss of SG heat removal capability due to the thermal stress.
The long term cooling capability with sufficient AFW resource should be demonstrated for the SLB with blowdown from both SGs.
Response 440.208:
l For a steat 'i"c _r"'b (SLB) with an assumed f ailure to close of a main steam isolation valve (MSIV) in the intact steam generator, a delay of emergency feedwater actuation may result in a complete depletion of the liquid inventory from both steam generators.
A SLB with conditions chosen to minimize the liquid remaining in the steam generators at the time emergency feedwater reaches the steam generators was analyzed.
The initial steam generator water inventory was minimized and the maximum time delay between emergency feedwater actuation signal and emergency feedwater delivery (60 seconds) was used.
For this case there was still more than 25,000 lbm of liquid in each steam generator when the emergency feedwater reached the steam generator. Steam generator dryout occurred about 50 seconds later.
Cooldown then continued with emergency feedwater flow to the dry steam generators.
All incoming feedwater proceeds tc be boiled off until the primary side temperatures are reduced to a value at which the primary to secondary heat transfer rate is less than that extracted by the boiling of all feedwater at approximately 20 minutes into the transient. Af ter this time, the steam generators begin to refill.
Steam generator thermal stress analyses show that the injection of cold emergency feedwater during such conditions does not,
- however, cause tube stresses to exceed design limits.
Hence, the heat removal capability of the steam generators is preserved.
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Besponse 440.20_8_1 The analysis presented in appendix SD of CESSAR-DC l
demonstrates that with a lower cooldown rate than that which occurs during a SLB there are more than 400,000 gallons of emergency feedwater remaining af ter reaching shutdown cooling entry conditions.
A lower cooldown rate requires more feedwater to achieve shutdown cooling conditions.
The emergency feedwater supply is, therefore, ample for long term l
cooling capability for a SLB with blowdown from both steam j
generators -- event if it were to be assumed that the total i
maximum emergency feedwater flow of 800 gpm per steam generator made no contribution to the cooldown during the first half hour of the event.
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Ouestion 440.209:
water is actuated on the low SG "In the analysis, the AFW In the SGTR level signal when the automatic mode is assumed.
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analysis when the high SG water level trip signal is cred teas sta for the reactor trip.
the water level instruments are subject to significant errors. r i
ef fects of level instrumentation errors on the safety analys s The applicant is results, which rely on the level instruments for accident mitigation."
Response 440.209:
USNRC Information Notice 92-54 discusses possible PWR pressurizer level inaccuracies caused by the degassing of the Non-reference leg during rapid system depressurizations.
for condensible gases that are added to the primary cool in i
the pressurizer, migrate to the reference leg via the These condensing pot and then diffuse into the reference leg.
the gas expands and rises during a
rapid system This would cause the pressurizer level give an inaccurate (high) reading.
The depressurization.
steam generator level instrumentation is much less likely to instrumentation to i
t experience this phenomena because of the lack of signif can quantities of dissolved gases in the feedwater (see CESSA Table 10.3.5-1) the steam generators.
feedwater is oxygen at a very The only dissolved gas in the The high low concentration (see CESSAR-DC, Table 10.3.5-2). steam generato steam velocities in the retention (and eventual migration and diffusion into the The reactor trip that occurs reference leg) highly unlikely.
during the early part of the natural circulation cooldown will result in a high secondary pressure which would not cause aLater in the degassing of the reference leg.
generator pressure is reduced corresponding to a plant relatively slow cooldown rate of 50 degrees F/hr.
Such a would not cause steam reduction in secondary pressure associated with liquid displacement generator level errors from the reference leg.
i Ouestion 440.210 Explain why the calculated DNBR decreases twice before it increases monotonously.
Response 440.210 The DNBR transient of Figure 15.2.3-13 resulted from a separate parametric analysis which sought a minimum DNBR rather than a peak pressure.
The parameters selected which minimized the DNBR resulted in a rapid pressurizer pressure response which opened the primary safety valves twice before the reactor was tripped on the second pressure rise, The core power and RCS pressure transients are shown in the attached figures.
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i SYSTEM 80+ LOSS OF CONDENSOR VACUUM CORE POWER VS. TIME 120.0 100.0 I
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Ou 40.0 I
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w 0.0 10.0 20.0 30.0 40.0 50.0 TIME, SECONDS
SYSTEM 80+ LOSS OF CONDENSOR VACUUM RCS PRESSURE VS, TIME 2900.0 2700.0 e
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2500.0 5
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R 2300.0 Q
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2100.0 f'
1900.0 C-
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O Ouestion 440.215:
On page 15.3.8 and Table 15.3.3-2, it is stated that "a high prirary system pressure and a lw core inlet tenperature were chosen to raximize the enount of failed fuel." A higher pressurizer pressure and a lower core inlet tenperature would result in a higher initial DE. Explain kty the transient would result in a raximum amount of failed fuel when the initial D E is assuned at a higher value.
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Response 440.215:
he initial DE is assuned at the lower value. We high pressure and low i
temperature initial conditions result in an initial DE being lower than that for the lower pressure and higher tenperature initial conditions.
this phenomenon occurs due to the operational characteristics of a CDlSS/CPC plant. During operation, a specified portion of the total core therral rargin is reserved for the safety analyses and is called the Regaired Overpower Margin (ROH4).
If this rargin is violated, an alarm will sound alerting the operator that the Power Operating Limit (POL) was violated. Determination of a violation of the RCR4 is perforned by COISS and all paraneters affecting DE are considered in this deternination.
If the plant is operating at a high pressure and low tenperature other parameters, e.g.,
F, will be allowed to vary in the more adverse g
direction as long as the required therral rargin is raintained.
We locked rutor event was initiated from this minimum therral margin.
The resulting initial DE with high RCS pressure and low RCS temture reflects this minimum therral rargin. thus, the benefit to DE of high pressure and lw tenperature are offset by the assuned variation of other D E related parameters in the more adverse direction. W e analysis was therefore based on the ccerbination of conditions yielding the minimum transient D M.
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a Ouestion 440.216:
Page 15.5-5 The maximum charging flow is assumed to be 150 gpm decreasing from 250 gpm in the existing analysis (CESSAR-DC, Amendment H).
Explain why.a lower charging flow is assumed for the limiting case analysis.
Response 440.216:
A 150 gpm charging pump flow is assumed for the limiting case analysis due to a change in the final de,ign of the CVCS resulting in a decrease in the maximum charging pump runout flow.
The charging pump runout flow has been reduced such that the maximum possible flow to the RCS is 150 gpm.
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e Question 440.217:
Page_15.5-6 It is stated that "a pressurizer absolute high level alar: at 65% of the pressurizer volume will prevent water from being discharged out of the pressurizer safety valves."
Confirm that the appropriate procedures are available and describe the operator actions to avoid water discharge from the PSVs in responding to the alarm.
r Response 440.217:
The words in CESSAR DC will be changed to read "A pressurizer absolute high level alarm at 65% of the pressurizer volume will alert the operator to the increase in water level."
The operator will prevent water discharge from the PSVs by stopping charging flow and increasing letdown.
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CESSAR naincuiou
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The 2713 lbs of steam discharged by the pressurizer safety valve are contained within the in-containment refueling water storage tank with no releases to the atmosphere.
The main steam safety valves discharge. 134,009 lbs of steam to.
the atmosphere prior to 1800 seconds.
At 1800 seconds, the operator stabilizes the plant and initiates plant cooldown, using the atmospheric dump valves.
15.5.2.4 Conclusions The peak RCS and steam generator pressures reached during the Pressurizer Level Control System malfunction with a - loss of offsite power at turbine trip and'the limiting single failure are 2682 psia and 1266 psia, respectively.
These pressures are less than--110% of the design ~ pressures.
Since this transient is-due primarily to an increase in primary inventory.which causes ~ an increase
.in RCS
- pressure, the DNBR increases-until reactor / turbine trip at which time the loss of offsite power resulting in a decrease in reactor coolant flow causes the DNBR to decrease to a minimum. of 1.62.
Therefore, the acceptance criterion regarding fuel performance is met.
A pressurizer absolute high level alarm at 65% of the pressurizer
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volume will prevent water from being discharged out of the_ /
. pressurizer safety valves.f An interval of 30. minutes is assured between the alarm and required operator action.
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.i Amendment N 15.5-6 April 1, 1993
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o-INSERT A e
i A pressurizer absolute high level alarm at 65% of the pressurizer volume will alert the operator to the increase in water level.
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Ouestion 440.218:
Since the AU/ block valves are credited for the SGTR analysis aM the pressurizer backup heaters are credited in the letdcun line break analysis, confim that both valves aM backup heaters are the safety grade w.punents.
Rcsporre 440.218:
1 The AU/ block valves are safety grade and are credited in the SGIR analysis to mitigate the consegaences of this event if a failure of an AU/
to close is asstred. However, the y pose of asem%g operation of the pressurizer backup heaters during th letdom line break event is to make the consequences of the event more adverse.
Therefore, they are not
" credited" to mitigate the consequences of this event and as such are not required to be safety grade.
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