ML18026A222

Forwards Revision 22 to FSAR

ML18026A222
Person / Time
Site:	Susquehanna
Issue date:	03/20/1981
From:	Curtis N PENNSYLVANIA POWER & LIGHT CO.
To:	Youngblood B Office of Nuclear Reactor Regulation
Shared Package
ML17138B875	List: ML18026A222
References
ER-100450, PLA-662, NUDOCS 8103230429
Download: ML18026A222 (177)

Text

REGOLAT'ORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:8103230429 OOC ~ DATE: 81./03/20 NOTARIZED: HO DOCKET ¹ FACIL:50 Susquehanna Steam Electric Station< Unit ir Pennsy'lva 05000387 388 usEruehanna Steam Electric Stationi Unit 2r Pennsylva 05000388 AUTHOR'FFILIATION Pennsylvania Power 8 Light Co ~

RECIPIENT AFFILIATION Licensing Branch 1

SUBJECT:

Forwards revised pages to FSAR ~

0ISTRISOTION COOS:

TITLE: PSAR/FSAR ROOTS ANDTS and COPIES RECE Related Correspondence IVES ILTR 3, ENCL lg SIZE: I+ 8'~

NOTES:Send I8,E 3 I8E 3 cooies copies FSAR FSAR 8

8 all all amends'5000387 amends'end 05000388 RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR'ENCL IO CODE/NAME LTTR ENCL ACTION: A/D LICENSNG 1 0 YOUNGBLOODEB 1 0 RUSHBROOKgtvI ~ 1 0 STARKgR ~ 04 1 1 INTERNAL: ACCID EYAL RR26 dUX SYS SR 07 CHKH ENG BR CORK PERF BR 08 10 1,

1 1 1 1

1 CONT SYS 8R EFF TR SYS 0'?

BR12 1

1 1

1 1

1 K%ERG PREP 22 0 EQUIP QUAL BR 13 3 3 GEOSC IKNCES 14 1 1 PULI FACT ENG BR 1 1 HYD/GEO 3R 15 2 2 I8C SYS BR ie 1 I8,E 06 3 3 L IC GUID BR 1 LIC QUAL BR 1 1 'LIATL KNG BR 17 1 MECH KNG 8R 18 1 1 MPA 1 0 NRC POR 02 1 1 OELD 1 0 OP LIC BR 1 POWER SYS BR 1? 1 PROC/TST REV 20 1 1 QA BR 21 1 1 RAD ASSESS RR22 1 REAC SYS BR 23 1 IÃ F IL 01 1 1 SIT ANAL BR 2a 1 CY NG BR25 1 1 SYS INTERAC BR 1 1 EXTERNAL: ACRS 27 16 16 LPDR 03 1 1 NSIC 05 1 1 TOTAL NU'vIBER OF COPIES RF QUIREO: LTTR 57 ENCL 51

TWO NORTH NINTH STREET, ALLENTOWN, PA. 18101 PHONEs (215) 770-5151 NORMAN W. CURTIS Vice Presirtent. Engineering 8 Construction-Nuclear 770.5381 March 20, 1981 Mr. B. J. Youngblood Licensing Project: Branch 81 Division of Project Management U.S. Nuclear Regulatory Commission Washington, DC 20555 SUSQUEHANNA STEAM ELECTRIC STATION FSAR CHANGES ER 100450 FILE 841-2 PLA-662 Enclosed please'ind forty (40) copies of changes to the Susquehanna Steam Electric Station Final Safety Analysis Report. Effected FSAR Sections are listed on the attachment to this letter.

Very truly yours, N. W. Curtis Vice President-Engineering tt Construction-Nuclear TEG/mks Enclosure yoo I 5

I/go PENNSYLVANIA POWER 8 LIGHT COMPANY 8~Psg g0489

SSES-FSAR TABLE 3.2-1 (Continued)

Pa e 30 NA None Applicable X Manufacturer's Standards

6) I - The equipment shall be constructed in accordance with the seismic requirements for the Safe Shutdown Earthquake, as described in Section 3.7.

NA - The seismic requirements for the Safe Shutdown Earthquake are not applicable to the equipment or structure.

7) Y - Requires compliance with the requirements of 10CFR50, Appendix B in accordance with the quality assurance program described in Chapter 17.

N - Not within the scope of 10CFR50, Appendix B.

8) The classification of the control rod drive water return line from the reactor vessel through the third isolation valve will be Group A. Beyond the third valve will be Group D, except as noted in Table 3.2-1.

9) The following qualification shall be met with respect to the certification requirements:

The manufacturer of the turbine stop valves, turbine control valves, turbine bypass valves, and main steam leads from turbine control valve to turbine casting shall use quality control procedures equivalent to those defined in General Electric Publication GEZ-4982A, "General Electric Large Steam Turbine-Generator equality Control Program".

2. A certification shall be obtained from the manufacturer of these valves and steam leads that the quality control program so defined has been accomplished.

10) 1. Instrument and sampling piping from the point where they connect to the process boundary and through the process shutoff (root) valve(s), isolation valve(s), and excess flow check valve, when provided, will be of the same classification as the system to which they connect.

2. All instrument lines which are connected to the reactor coolant pressure boundary and are utilized to actuate safety systems shall be Group B from the process shutoff (root) valve(s), isolation valve(s), or excess flow check valve, when provided, to the sensing instrumentation.

3. All instrument lines which are connected to the reactor coolant pressure boundary and are not utilized to actuate safety systems shall be equality Group C from the 8103230429

SSES-FSAR TABLE 3.2-1 (Continued)

Pa e 31 process shutoff (root) valve(s), isolation valve(s),

excess flow check valves, when provided, to the sensing instrumentation.

4. Other instrument lines:.

a) Those connected to special equipment or Group D system pressure boundaries and utilized to actuate safety systems will be Group C from the system pressure boundary through the process shutoff valve(s) to the sensing instrumentation.

b) Those connected to Group B and Group C systems and utilized to actuate safety systems shall be of the same classification as the process system to the sensing instrumentation.

c) Those connected to Group B and Group C systems and not utilized to actuate safety systems will be of Group D classification except for those Group C systems by GE utilizing capillary (filled and sealed) instrument lines.

d) Those connected to Group D systems and not utilized to actuate safety systems will be of Group D classification.

5. For Group A, B, and C systems, the sample line beyond the process shutoff (root) valve(s) or isolation valve(s) will be Group B through the penetration and Group D from the isolation valve to the shutoff valve outside of the sample station.

ll) The HPCI and RCIC turbines do not fall within the applicable design codes. To ensure that the turbine is fabricated to the standards commensurate with their safety and performance requirements, General Electric has established specific design requirements for this component.

12) The hydraulic control unit (HCU) is a General Electric factory assembled, engineered module of valves, tubing, piping, and stored water which controls a single control rod drive by the application of precisely timed sequences of pressures and flows to accomplish slow insertion or withdrawal of the control rods for power control, while providing rapid insertion for reactor scram.

Although the hydraulic control unit is field installed and connected to process piping, many of its internal parts differ maikedly from process piping components because of the more complex functions they must provide. Thus, although the

THIS FIGURE HAS BEEN INTENTIONALLY LEFT BLANK REV. 22, 4/81 SUSQUEHANNA STEAIN ELECTRIC STATION UNITS 1 AND 2 FINALSAFETY ANALYSIS REPORT THIS FIGURE HAS BEEN INTENTIONALLY LEFT BLANK FIGURE 3. 6-9

SSES-FSAR TABLE 3 9-2 INDEX LOADING COMBINATIONS~STRESS LIMITS AiND ALLO@ ABLE STRESSES a Reactor Vessel Pressure and Shroud Support Assembly

b. Reactor Vessel Internals and Associated Equipment

c. Reactor Rater Cleanup Heat Exchangers d Class 1 Main Steam Piping

e. Class 1 Recirculation Loop Piping

f. This item intentionally left blank

q. Safety/Relief Valves (Main Steam)

h. Main Steam Isolation Valve

i. Recirulation Pump Reactor Recirculation System Gate Valves (Suction/Discharge)

k. This item intentionally left blank

1. Standby Liquid Control Pump

m. Standby Liquid Control Tank

n. ECCS Pump

o. RHR Heat Exchanger p R'ACU Pump

q. RCIC Turbine RCIC Pump Se New Fuel Storage Racks

t. High Pressure Coolant Injection Pump u This item intentionally left blank

v. Control Rod Drive Housing Jet Pumps aa. Control Rod Guide Tube ab Incore Housing ac Reactor Vessel Support Equipment CRD Housing Support Rev. 22, 4/81

SSES-FSAB TABLE 3 9-2 ZNDEX Continued ad. This item intentionally left blank ae. HPCZ Turbine. Design Calculations af. High Density Spent Fuel Storage Racks Rev. 22, 4/81

TABLE 3.9-2(s) (page 1 of 2)

NEW FUEL STORAGE RACKS ALLOWABLE CALCULATED CRITERIA LOADING LOCATION STRESS (.7 ULT) STRESS

1. NEW FUEL STORAGE RACKS FAULTED CONDITION "A" Stress due to normal upset l. Dead Loads 1. Beam (Axial) l. 26,0008/in2 2

1. 18,9058/ig 2

or emergency loading shall 2. Full Fuel Load in 2. Beam (Trans.) '2.'6,000/I/in> 2. 7,005///in not cause a failure so as to rack 3. Combined =

3. 26, 0008/in 2. 25,9108/in result in a critical array. 3. S.S.E.

4. Thermal (not appli-cable)

2. SOURCE OF ALLOWABLE STRESS (.7 ULT) a~ ASTM B308 Alloy 6061-T6

b. ASME Code Boilers and Pressure Vessels, Sect. III, NA C~ Product Safety Standards for Bt&-6-Mark III, Sect. VI, A. (3)

d. ASME Pressure Vessels and Piping: Design and Analysis, Volume One, Page 69.

e. ASTH code for Boilers and Pressure Vessels was selected on the premise that data used from this source would necessarily be on the convervative side as applied to the fuel storage rack calculations.

Rev. 22, 4/81

TABLE 3.9-2(s e 2 of 2)

S- S.S.E. loads derived by dynamic analysis. Total stress refers to combined earthquake and thermal load

=

at highest expected pool temperature. Earthquake stresses obtained by square root of the sum of- the squares method for a response due to tri-axial excitation. Stress given is the highest in the total structural array.

4. NEW FUEL STORAGE RACKS FAULTED CONDITION"B" (Location-See Not Applicable Not Applicable Par. 6, Below)

Stresses due to normal upset (See Below, Par.~)

or emergency loading shall not cause a failure so as to result in a critical array.

FAULTED CONDITION "B": Condition "B" is an emergency condition in which the stress limit is equal to the yield strength at 0. 2% offset. The racks were tested to determine their capability to safely withstand the accidental, uncontrolled, drop of a fu'el bundle from its fully retracted position into the weakest portion of the rack.

6. METHOD OF TESTING: Four (4) rack castings were subjected to impact loads ranging from 1908 ft. lbs.

to 4070 ft. lbs. which were generated by dropping simulated fuel bundles weigh-ing 660 lbs. from heights varying from 3.0'nd 6.17'. Racks were aligned in pairs and simulated bundles were dropped on both racks at the flange area. Both .

center impact and end impact tests were conducted. (Two (2) of the racks were X-Ray examined prior to testing. Strain gages were mounted on racks to ascer-tain max. strain and accelerometers were mounted on bundles to determine "G" loads.)

7. TEST RESULTS: A total of nineteen (19) tests were performed with drop height increased at each test. First failure occurred due to a central impact on rack No. 3 from a max.

height of 6.17', (Test 813). Racks 81 and i02 both failed from a center impact caused by a load dropped from a height of 5.33', (Test f/19). Accelerometer readings are not available due to the inability to adequately affix the accel-erometer to the simulated fuel bundle.

Rev. 22, 4/81

SSES FSAR TABLE 3.9 2 (af) e 1 of 2 HIGH DENSITY SPENT FUEL RACKS TYPES OF ANALYSIS PERB3MED DYNAMIC ANALYSIS:

A dynamic modal analysis using the seismic, SRV, and DX'A response spectra was performed on a simplified model consisting of 6 racks (1 quadrant). 'Ihe resulting loads on the corner module were extracted and a more detailed analysis per forned.

STATIC ANALYSIS:

A detailed finite element (1364 elanents) model of the corner module was developed and a static analysis performed using the loading results of the dynamic analysis. The section descriptions, allowable stresses and stress ratios for the detailed model are given on page 2 of this table.

FUEL RA'ITLING ANALYSIS:

A time history analysis was performed to determine local impact loads due to fuel rattling. A canparison of the support loads from the fuel rattling analysis with those of the response spectrum analysis showed that the fuel rattling results are less than or equal to the response spectrum results.

Analysis of the poison can was completed using the local impact loads.

MODEL IMPACT ANALYSIS:

An equivalent static load was determined for the following drop conditions:

1) 18" fuel drop on corner of top casting

2) 18" fuel drop on middle of top casting

3) fuel drop full length through the cavity impacting bottom casting at the middle.

For the first 2 cases the equivalent static loads calculated were combined with dead load and applied to the detailed model. For the 3rd case, the ultimate load of the bundle shearing out of the fuel seat was determined and combined with dead load. This combined load was then applied to the detailed nadel.

Rev. 22, 4/81

SSES FSAR TABIE 3.9-2 (af ), page 2 of 2 HIGH DENSITY SPENT FUEL RACK

SUMMARY

OF RESUL'LS FOR THE DETAIIZD MODEL ELEMENTS NORMAL DESIGN ACCIDENT AND AUlMABLE NORMAL OPERATING CONDITION EKTREME ENVIRONMENTAL STRESSES CONDITIONS MAX SECT. fa fb fbx STRESS fbx STRESS NO. SECTION DESCRIPTION Fa Fby Fbx RATIO Fbx Fby (1) RATIO(l) 1 Top Grid Outer Section 9941 15760 15760 .026 .009 .747 .78 .018 .006 .715 .74 2 Top Grid Inner Section 9420 15760 15760 .057 .055 .813 .93 .040 .039 .766 .85 3 Bottom Grid Outer Sect. 8830 15760 12120 .062 .248 .108 .42 .062 .248 .108 .42 4 Bottom Grid Inner Sect. 8550 15760 12120 .005 .831 .013 .85 .005 .831 .013 .85 Bottcm Grid Outer 9650 15760 12120 .047 .249 .269 .57 .047 .249 .269 .57 Section Near Leg Bottom Grid Inner 9530 15760 12120 .046 .508 .248 .80 .046 .508 .248 .80 Section Near Leg 7 Bottom Grid Foot 10250 15760 12120 .132 .001 .13 .160 0 .003 .16 8 Bottan Grid Foot 11020 14180 14180 .161 .003 .16 .195 0 .006 .20 9 1/2" Plate 3320 Fv = 1390 99(2) 76(2) 10 7/8" Plate 17370 F = 10970 92(2) .92(2) a bv fbx (1) Stress Ratio Fa +  %' Fbxx NOZE (2) Plate Stress Ratio = f> fx Allowable stresses are

+ factored up per Table 9.1-7a of the SSES-FSAR.

Rev. 22, 4/81

SS ES-FS AH 4 .4.6 I N S TH H:.5 E N T A T I 0 N R E Q0 I H E iJ E N TS The reactor vessel instrumentation monitors he Key reac.or vessel operatinq parameters during planned operations. Thi-ensures suffi"ient control of the paramete=s. The followinq reactor vessel sensors are discussed in Subsection 7.7.1.l.

(1) Reactor Vessel Temperatu"e (2) Reactor Vessel ~r,'ater Level (3) Reactor Vessel Coolant Flow Hates and Differen=ial P re ssure s (4) Reactor Vessel Xnt mal Pressure (5) Neutron .'lonitoring System

4. 4.6 1 Loose Pa" ts ilonitoring The Loose Parts Monitoring System for Susquehanna SES is discussed in Subsections 7.7.1.12 and 7.7.2.12.

4

4.7 REFERENCES

4.4-1 General Electric Thermal Analysis Basis (GETAB): Data, Cor"elation and Desiqn Application, Gene al Electric Company, January 1977, (N"D0-10958A).

4.4-2 Co" Flow Dis ribution in a Modern Boiling Mater Reactor a- Measured in lJonticello, Auqus" 1976, (NFDO-10722A) .

4. 4-3 H.C. Nartinelli and D. F.. Nelson, "Prediction of Pressure Drops Du inq Forced Convection Boilinq of:

Hater," ASHZ Trans., 70, pp 695-702, 1948.

4 4-4 C. J. Baroczy, "A Systematic Correlation for Two-Phase Pressure Drop," Heat Tran"fer Conference (Los Angeles),

AECLE, Preprint No. 37, 1966.

4 4-5 Jens, R. H., and Lottes, P.A, Analysis of Heat Transfer, Burnout, Pressure Drop, and Density Data for High Pressure dater, USAEC Report-4627, 1972.

4. 4-6 Neal, L G., and Rivi, S. il., "The Stabilit y of Boiling-cfater Reactors and Loops," Nuc1ear Science and Eng ineer inq, 30 p. 25, 19 67.

Rev. 22, 4/81 4. 4-27

1.6 TOTAL CORE STAB ILITY 1.4 ULTIMATEPERFORMANCE LIMIT 1,0 O

I L

0 0.8 NATURAL CIRCULATION 0.6 105'%OD LINE 0.4 02 0

0 20 40 80 120 PERCENT POWER f

SUSQUEHANNA STEAM LECTRIC STATION UNITS 1 AND 2 FINALSAFETY ANALYSIS REPORT CORE REACTXVITY STABILXTY FIGURE 4 4

SSES-TSAR .

separated housing, gives a force of approximately 35,000 lb.

This force is multipli d by a fa"tor of 3 for impact, conservatively assuming that the housing travels through a l-in.

gap before it conta"ts the supports. The total force (105,000 1b) is then treated as a static load in design.

All CRD housing support subassemblies are fabricated of commonly available structural steel, except for the disc springs, which are Schnorr, Type BS-125-71-8.

6.2 ~

Evaluations of the CRDS This subject is covered under nuclear safety and operational analysis (NSOA) in Appendix 15A, Subsection 15A. 6. 5.3.

4.6. 2.3 Safety- Evaluat.iou-Safety evaluation of tee control rods, CRDS, and control rod drive housing supports .is described below.. Purther description of "ontrol rods is contained in Section 4.2.

4.6.2.3.1 - Control Rods 4.6 2..3;1.1 Haterials Adequacy -Thro~uhout Design lifetime The adequacy of the materials throughout the design life was evaluated in the mechanical design of the "ontrol rods. The primary materials, 84" powder and 304 austenitic stainless steel, have been found suitable in meeting the demands of the BQR environment.,

Rev. 22, 4/81 4 6-20

SSES-FSAR that are automatically actuated can also be maaually actuated from the main control room. A single failure ia any electrical system is analyzed regardless of whether the loss of a safety function is caused by either component failing to perform a requisite mechanical motion, or component performing an unnecessary mechanical motion.

6.2.4.4 Tests and Ins ections The containment isolation system is preoperationally tested in accordance with the requirements of Chapter 14.

The containment isolation system is scheduled to undergo periodic testing during reactor operation. The functional capabilities of power operated isolation valves are tested remote manually from the control room. By observing position indicators and changes in the affected system operation, the closing ability of a particular isolatioa valve is demonstrated.

A discussion of testing and iaspection, including leak tightness testing, pertaining to isolation valves is provided in Subsection 6.2.6 and ia Chapter 16. Table 6.2-12 lists all isolation valves.

Instruments will be periodically tested and inspected. Test and/or calibration points will be supplied with each instrument.

Excess flow check valves (EFCV) shall be periodically tested by opening a test drain valve downstream of the EFCV and verifying proper operation.

With the exception of the CRD insert and withdrawal lines, the penetrations listed in Table 6.2-12 are Type C tested. The test methods and acceptance criteria are listed in Subsections 6.2.6 and 3.9.6.2.

6.2.5 COMBUSTIBLE GAS CONTROL IN CONTAINMENT The combustible gas control system is provided, in accordance with the requirements of General Design Criterion 41 of Appendix A to 10CFR50, to control the concentration of hydrogen withia the containment following a loss-of-coolant accident (IOCA).

Rev. 22, 4/81 6.2- 4S

SSES-ESAR TABLE 6.2-22 LEAKAGE RATE TEST LIST Inboard Isolation Barrier Outboard Isolation Barrier Exemption Type Barrier Description/ Barrier Description/ to IOCFR50 Penetration Description Test Valve No. Notes* Valve No. Notes* Appendix J Required X-I Equip. access hatch B Double 0-ring X-2 Equip. access hatch Double 0-ring uith personnel lock X-2 Personnel lock barrel B Inner door/barrel 1>2 Outer door/barrel 1>2 X-2 Personnel lock inner door B Double 0-ring 1,3 X-2 Personnel lock outer door B Double 0-ring 1,3 X-3A Spare Cap X-3B Primary Containment 10 10,11 Pressure Inst.(2)

X-3C Spare A Cap X-3D Spare A Cap X-4 Dry@oil head access manhole Double 0-ring Dryuell head Double 0-ring X-5 Spare Cap X-6 CRD removal hatch Double 0-ring X-7A Main steam HV-IF022A 4>5,17 HV-IF028A> HV-IFOOIB, 4>19 Yes PT IN06IB,~I1051 X-78 Hain steam ~ C HV-IF022 B 4,5,17 HV-IF028B> HV-IFOOIF 4>19 Yes PT-IN061F, PT-IN051F X-7C Hain steam C IW-IF022C 4,5,17 HV-1E028C> HV-IFOOIK 4>19 PT-IN061K> PT-IN051K X-7D Hain steam C IAf-IF022D 4,5,17 HV-IF028D> HV-IFOOIP 4,19 Yes I I PT-IN061P> PT-IN05IP X-8 Hain steam line drain C HV-IF016 17> 18 HV-IF019 19 X-9A Feeduater C IFOIOA 14>18 HV-IF032A> IN-IF013, 14,19 HV-IF042, HV-1F104 Rev ., 4/81

SSES-FSAR TABLE 6.2-22 Continued Pa8c 6 Inboard Isolation Barrier Outboard Isolation Barrier Exemption Type Barrier Description/ Barrier Description/ to 10CFR50, Penetration Description Test Valve No. Notes* Valve No. Notes* Appendix J Required X-58A Main steam,RWCU inst (4) A 10 10,11 X-58B Hain steam,RWCU inst (2) h 10 10,11 X-59h Reactor level inst A 10 10,11 X-59B Reactor level inst h 10 10 >11 X-60A 0 sample C SY-15740B 18 SV-15742B 11 >19 X-60A 0 sample C SV-15776B l8 SV-15774B 11>19 X-60A 0 sample C SV-15750B 18 SV-15752B 11,19 X-60B Reactor Water Sample C IN-IF019 17>18 UV-1F020 19 X-61A Demin. Water C 1-41-018 18 1-41-017 19 X-61A Flow Instrumentation h 10 X-61A ILRT Leak Veriiication C 1-57-193 18 1-57-195 19 X-61B Main steam inst (2) h 10 10 ~ 11 X-62A Main steam inst (2) h. 10 10,11 X-62B Main stcam inst (2) 10 10>11 X-63A Hain steam inst (2) h 10 10>11 X-63B Hain stcam,RWCU inst (3) 10 10, 11 X-64A Hain steam inst (2) A 10 10,11 X-64B Prcssure inst (3) A 10 10,11 X-65A Reactor level inst h 10 10,11 X-65B Reactor level inst 10 10,11 X-66A Reactor level inst h 10 10>11 X-66B Reactor level inst 10 10>11 X-72A Liquid radwaste C liV-16116hl 17, 18 HV-161 16A2 11,19 X-728 Liquid radwaate C UV-16108A1 17, 18 UV-16108A2 11,19 Rev. 22, 4/81

SSES-FSAR TABLE 6.2-23 I VITIAL A'.ED BOUN DAH Y CONDITIONS FOR I V ADV ERT ENT SPR A Y ACTUA T ION STIJDY Tz.m e Zero

-00 to Drvwell Volume ('t~) 239600 239600 Pressure (PSI A) 14.8 34. 83 Tem pera t ure (F) 150 259 Relative Humidity (n) 100 100 Spray Rate (GPN/ TRANS) 0/0 10700/1 Met well Volume Vapor Region (Ft ~) 148590 145900 Suppression Pool (Ft~) 131550 131550 P ressure (PSI A 14.8 30. 28 Temperature (F) 50 50 Relative Humidity (K) 100 100 Suppression Pool Free Surface Area (Ft~) 5277 5277

>letwegl-to-Drvwell Vacuum Breake. "-

Number of Valve Assemblies of 5 Flow Area Per Assembly (F t~) 2.05 Flow Coefficient 0.35 Assumed Vacuum Breaker Lifting P ressure (puid) 3 RHR System Drgwell Spray Mode Service Mater Flow Hate (GPM) 9000 Ser vice Mater Temperature (F) 32 Heat Exchange Effectiveness 0. 245 Rev. 22, 4/81

SSES-FSAR 6.3.5 INSTRUMENTATION RE UIREMENTS Design details including redundancy and logic of the ECCS instrumentation are discussed in Section 7.3.

All instrumentation required for automatic and manual initiation of the HPCI, CS, LPCI and ADS is discussed in Subsection 7.3.2 and is designed to meet the requirements of IEEE 279 and other applicable regulatory requirements. The HPCI, CS, LPCI and ADS can be manually initiated from the control room.

The HPCI, CS, and LPCI are automatically initiated on low reactor water level or high drywell pressure. (See Table 6.3-2 for specific initiation levels for each system.) The ADS is automatically actuated by sensed variables for reactor vessel low water level and',drywell high pressure plus the indication that at least one LPCI pump or both CS pumps in the same loop are operating. The HPCI, CS and LPCI automatically return from system flow test modes to the emergency core cooling mode of operation following receipt of an automatic initiation signal.

The CS and LPCI system injection into the RPV begin when reactor pressure decreases to system discharge shutoff pressure.

HPCI injection begins as soon as the HPCI turbine pump is up to speed and the injection valve is opened since the HPCI is capable of injecting water into the RPV over a pressure range from 150 psig to 1145 psig.

6.3.6 NPSH MARGIN AND VORTEX FORMATION AFTER A PASSIVE FAILURE IN A WATER TIGHT ECCS PUMP ROOM NPSH calculations for ECCS pumps have shown adequate margin to assure capability of proper pump operation after a pool level drop due to a worst case passive failure in an ECCS water tight pump room. This capability will be verified during preoperational testing assuming a passive failure in the ECCS pump room resulting in the lowest pool level with subsequent operation of the ECCS pump with the smallest NPSH margin above NPSH required. ECCS pump data is presented in Figures 6.3-75 thru 6.3"78.

The pool level drop has been determined assuming a passive failure in a ECCS water tight pump room with operator action 10 minutes after an alarm in the room indicating high water level.

This lowest suppression pool water level will also be used during preoperational testing to verify the absence of vortex formation in the flow approaching the suction strainers in the pool during ECCS pump operation. Pump performance and pump noise will be monitored during these tests to determine if to suction flow conditions in the suppression pool.

pumps are sensitive Rev. 22, 4/81 6.3-32

SSES-FSAR 7.3.1.1b.8.5.3.7 Actuated Devices Refer to Subsection 9.4.8.

7.3.1.1b.8.5.3.8 Se aration The instrumentation, controls, and power supply of the ESSW pumphouse are divisionally separated. Two bays provide physical and electrical separation between Division I and Division II.

7.3.1.1b.8.5.3.9 Su ortin S stems The instrumentation and controls of the ESSW pumphouse ventilation system are powered from Class 1E 125 V dc and 120 V ac systems. These electrical systems are discussed in Chapter 8.

The ESSW pumphouse unit heaters support the ventilation system as discussed in Subsection 9.4.8.

7.3.l.lb.8.5.3.10 S stem Parts Not Re uired for Safet The parts of the ESSW pumphouse ventilation system not required for safety are as follows:

a) All electric unit heaters, see Subsection 9.4.8 b) Instrumentation for monitoring airflow from the ESSW pumphouse ventilation system c) Instrumentation for alarming in the main control room of high-high and low-low temperatures in the ESSW pumphouse 7.3.1.lb.8.5.4 ESF Switch ear (SWGR) Rooms Coolin S stem For the description of operation of the above system refer to Subsection 9.4.2.2.

Rev. 22, 4/81 7.3-101

SSES-FSAR one group will not interfere with proper operation of the redundant portions of the system in Section 8.1.

I 7.3.2 a.5.4.3 IEEE Standard 338 (1975)

The capability for testing the suppression pool cooling instrumentation and control system is discussed in Section 7.3.2.6.4.1.9 and 7.3.2.6.3.1.10.

7.3.2a.5.4.4 IEEE Standard 379 (1972) a The single failure criterion of IEEE 279 (1971), paragraph 4.2 as further defined in IEEE 379 (1972), "Application of the Single Failure Criterion to Nuclear Power Generating Station Protection System," is met as described in Section 7.3.2a.5.4.1.2.

7.3.2a.5.4.5 IEEE Standard 384 (1974)

Independence of suppression pool cooling equipment is demonstrated in the Section on Conformance to IEEE 279 (1971) paragraph 4.6 and IEEE 308 (1974). See Sections 7.3.2a.5.3.1.6 and 7.3.2a.5.3.2.

7.3.2a.6 throu h 7.3,2a.ll These Subsection numbers were not used.

7.3.2a.12 Additional Desi n Considerations Anal ses 7.3 'a.12.1 General Plant Safet Anal sis I

The examination of the 'subject ESF system at the plant safety analyses level is presented in Chapter 15 and Appendix 15A.

Rev. 22, 4/81 7.3-196

SSES-FSAR 7.6.1b.1.1.8 Environmental Consideration The pressure transmitters located outside the primary containment are designed and qualified to withstand all anticipated environmental conditions in accordance with IEEE-323-1974 and IEEE-344-1975.

7.6.1b.1.2 Primary Containment and Suppression Pool Temperature Monitoring System 7.6.1b.1.2.1 System Identification The Suppression Pool systems are designed to monitor the temperature in the primary containment and suppression pool during normal plant operations and after LOCA.

7.6.1b.1.2.2 Safety Evaluation The indication of containment temperatures in the control room is required for post accident monitoring and is safety related. The initiating contacts for the automatic start of the drywell fans are derived from electronic switches in the temperature sensing loop. This function is safety related.

The system design conforms to all applicable criteria for physical separation and divisionalization. Refer to Subsection 7.3.l.lb. The hardcopy timeplot of the containment temperatures is operating history only and is not safety related. However, redundant systems are provided.

iO The indication of suppression pool temperature in the control room is required to ensure that the plant is always operating within the technical specification limits. Manual, operator action is required to maintain the plant within the specifications. Suppression pool temperature is also required for post accident monitoring. Both of these functions are safety related.

The system design conforms to all applicable criteria for physical separation and divisionalization. Refer to subsection 7.3.1.lb.

The hardcopy timeplot of suppression pool temperature is operating history only and is not safety related. However, redundant systems are provided and are devisionalized.

The primary Containment and suppression chamber temperature elements and temperature indicators will be qualified to operate following a DBA.

I Rev. 22, 4/81 7.6-57

SSES-FSAR 7.6.1b.1.2.3 Power Sources The safety related instrumentation is powered from divisionalized power sources. Division I Class IE bus (120 V ac) powers Loop A, Division II Class IE bus (120 V ac) powers Loop B.

Four dual element RTDs per redundant system are located in the primary containment to sense the temperature at the following elevations:

a) Reactor pressure vessel head b) Upper platform c) Lower platform d) . Drywell (below reactor pressure vessel).

Two redundant temperature elements are located in the suppression chamber.

The selected location for the temperature sensors helps the operator to define the area of the heat source within the primary containment.

The signal from the RTD elements are amplified by electronic temperature transmitters to drive meters, recorder channels, and alarm switches in the control room.

Two redundant indicators, for the primary containment are located in the main control room. The initiating contacts for the high speed start of the drywell cooling fans (refer to system description in Section 9.4) and derived from the two redundant temperature sensing elements located in the service area of the fans. If high temperature is detected the electronic switches will initiate the high speed start of the drywell cooling fans.

Electronic signal converters with full electrical input-output isolation are placed between safety related instrumentation and the input channels to the recorders.

Two redundant multipoint recorders for the primary containment temperature monitoring system provide a permanent history of all RTD measurements to the operator in the control room.

Each temperature sensing circuit is equipped with alarm switches and initiate one control room alarm per redundant channel.

Rev. 22, 4/81 7.6-58

SSES-FSAR One temperature indicator for the primary containment is located on the remote shutdown panel. Refer to Subsection 7.4.1.4 for system description. Instrument ranges are defined in Section 7.5.

7.6. lb.2.4b Equipment Design - Su~pression Pool Temperature The suppression pool temperature is monitored by two redundant systems, each of which performs as described below.

Eight RTD's per redundant system are located in the suppression pool approximately six inches below the minimum pool water level. These sensors are located around the pool in order to provide a good spatial distribution of pool temperature. Refer to Table 7.6-9 for the exact location of these sensors.

The signals from the senosrs are processed by an electronic unit located in the control room. This electronic unit converts the RTD signals into degrees Fahrenheit and computes the average of the eight temperatures. If one of the RTDs fails, an error alarm is generated, and the failed RTD may be removed from the calculation of the average by operator action. The average value is displayed by digital indicators located both on the electronic unit and on the main control board. A keyboard allows the operator to display any individual temperature input.

A high temperature alarm is generated by comparing the average temperature to several internally stored setpoints. The alarm condition is displayed by status lights located both on the electronic unit and on the main control board. Electrically isolated outputs interface with an annunciator located on the main control board.

A digital printer located on the electronic unit periodically prints the average temperature, plus the individual temperatures, plus the current date and time. Trending information may also be printed at the operator's request.

Alarm conditions are printed along with the temperature.

Electrically isolated digital and analog signals are provided to interface with other plant information systems. The electronic unit has a self checking diagnostic system that provides an error alarm if a failure is detected in any part of the system.

In addition to the eight temperature sensors mentioned above, there are four additional sensors associated with Division I. These sensors are located in the suppression pool, sixteen feet below minimum water level. They are used for display only and are not used in the calculation of average temperature and are not redundant.

Instrument ranges and accuracies are defined in Table 7.5-3.

Rev. 22, 4/81 7.6-59

SSES-FSAR

7. 6.-1h -1 2. 5- Redundancy-Redundant instrumentation is provided for the containment and suppression pool temperature monitorinq system 7~6; 1b -1 .2. 6- - Se D a ra t i on-J Physical and electrical separation is provided for the safety related iastrumentatioa. Nonsafety circuits are isolated by electronic converters vith .full input-output .isolation.

7,6 Pb,-1 2~7 genatiooaZ.. Consideration-The system is designed to function during normal plant operation and after a DBA.

7 6 11.-1.2 8- -Zn~ironmental -Consideration-All temperature seasing elements located inside the containment are desiqned. to operate. in the normal operating environment, durinq and after a LOCA. All electronic eguipment and indicating devices are located within the control structure.. Expected environmenta1 coaditions are defined in Chapter 3.

7-,6~ 4k.,~1- Q-- ~ggesgigg. Qoo3. - Wage~Level- monitoring System.

7.6ilb=-l 3=-1-- System- Tdentification-The instrumentatioa for suppression pool water level monitoring is desiqned to provide indicatioa and a record in the control room of the suppression pool'level durinq normal plant operation and in accident conditions, including a LOCA.,

Rev. 22, 4/81 7.6-59a

SSES-FSAR TABLE 7.6-9 Su ression Pool Tem erature Sensor Locations Azimuth Radius 36030'8o 34'-6" 34 I 6 II 100o30'02o 44'4'4 I 6ll 141o30'43o 34'-6" 179o 180 44'4'4'-6" 30'16o30'18o 34 I 6ll 268o30'70o 44'4'4 318o I 6ll 34 I 6ll 319030'48 30'50o 44'4'ev.

22, 4/81

SS ES-FSAR I

7 7 CONTROL SYSTEMS NOT REQUIRED FOR SAFETY

7. 7 1 DESCRIPTION-This subsection discusses instrumentation controls of systems whose functions are not essential for the safety of the plant and permits an understanding of the way the reactor and important subsystems are controlled. The systems include:

(1) Reactor vessel instrumentation VLSSS (2) Reactor manual control system instrumentation and controls, NSSS (3) Recirculation flow control system instrumentation and controls NSSS

{0) Reactor feedwater system instrumentation and controls NSSS (5) Pressure regulator and turbine - qenerator system inst umentation and .controls non-NSSS (6) Neutron monitoring system TIP (7) Process computer system instrumentation NSSS (8) Neutron monitoring system - traversing in-core probe NSSS (9) Reactor water cleanup system instrumentation and controls NSSS (10) Refueling interlocks system (ll) Nuclear Pressure Relief System instrumentation 5 controls (12) Rod block monitor system (13) Loose parts monitoring system 7.7.~~ . Reacgog Vessel - Instrumentation Figures 5.1-3a and 5.1-3b show the instrument numbers, arrangements of the sensors, and sensing equipment used to monitor the reactor vessel conditions. Because the reactor vessel sensors used for safety systems, engineered safeguards, and control systems are described and evaluated in other portions of this document, only the sensors that are not required for those syste ms are described in this subsection.

Rev. 22, 4/81 7& 7 1

SSES-FSAR 7.7.1.11.1.5 Testability 0 The rod block monitor channels are tested and calibrated with procedures given in the applicable instruction manuals. The RBMs are functionally tested by introducing test signals into the RBM channels.

7.7.1.11.2 Environmental Considerations (See description for APRM, Subsection 7.6.la.5.6.2) 7.7.1.11.3 Operational Considerations When increasing power, the set-up permissive lamp will light at which time the operator must evaluate conditions before manually changing to the next higher rod block set point line.

7.7.1.12 Loose Parts Monitorin~ System The Loose Parts Monitoring System will monitor, alarm and record the Reactor Vessel acoustics for the presence of internal loose parts in accordance with R.G.1.133 Draft-2 Rev. 1.

The system will monitor the points listed below. When an impact event signal exceeds a selectable amplitude, an alarm will occur and peak impact and impact repetition will automatically be recorded and timed sequentially, for each selected channel.

Eight piezoelectric accelerometers are attached externally to the Reactor Vessel:

a. Two mounted approx. 180 apart on or near the main steam lines to monitor the upper head regions.

b. Two mounted approx. 180o apart on or near the feedwater lines to monitor the upper vessel regions.

c. Two mounted approx. 180 apart and at 90 rotation from the upper vessel sensors mounted on or near the recirculation suction lines to monitor the vessel core plate region.

Rev. 22, 4/81 7.7-62

SSES-FSAR

d. Two mounted approx. 90 apart, one on a CRD Housing and the other on the RPV drain piping, to monitor the lower vessel regions.

7.7.1.12 Nuclear Pressure Relief System 7.7.1.12.1 System Identification The Nuclear Pressure Relief System, consisting of safety relief valves and associated circuitry, is designed to limit nuclear steam supply system pressure under various modes of reactor operation.

7.7.1.12.2 Equipment Design The Nuclear Pressure Relief System controls and instrumentation consist of manual control/pressure sensor channels each dedicated to its respective safety relief valve and associated valve operator (solenoid operated air pilot valve). The pilot valve controls the pneumatic pressure applied to the air cylinder operator. Upon energizing the pilot valve, pneumatic pressure is directed from the accumulator to act on the air cylinder operator causing the safety relief valve to open. Upon again de-energizing the pilot valve, air in the air cylinder is exhausted and the accumulator is once again isolated via the de-energized pilot valve. An accumulator, one for each valve, is included with the control equipment to store the pneumatic enexgy for safety relief valve operation. Safety relief valves are automatically initiated by high reactor pressure conditions. Cables from the pressure sensors for vessel pressure are routed Rev. 22, 4/Sl 7.7-62a

SSES-FSAR 10"-FR50- Appendix A.

Cri teria The RBM provides an interlocking function in the control rod vithdraval portion of the "RD reactor manual control system.

This design is separated from the protective functions in the plant to assure their independence.

Th RBH is designed to preven't inadvertent control rod. vithdraval given an imposed sinqle failure vithin the RBN. One of the tvo RBH channels is sufficient to provide an appropriate control rod vithdraval block.

En addition, the RBN has been designed to meet "appropriate protection system criteria....acceptable to the Regulatory Staff." (Reference 7.7-2) 7.7.2.12 Loose Parts Honitorin~ System The LPNS is not a safety-related system. Tt has been designed in accordance with Regulatory Guide 1.133, Rev. 1, Draft 2.

7.7 2;l2 - Nuclear Pressure Relief-- System Igstgumentation and

- gotltrols-

)@7 $ ~12 Q.- - General- Fuactioaai- Begu irements Conformance The Nuclear Pressure Relief System is designed to provide the nu"lear steam supply pressure relief function vithout jeopardy to the saf ety-related A DS f unction, dis" ussed in Section 7. 3.

7,4 2~4,2 2-- Specific" Regulatory Requirements (1) 10CPR50 Appendix A - "riterion 10.

The Nuclear Pressure Relief System provides additional means for minimizing the probability of abnormal reactor coolant pressure boundary leakage.

(2) 10CPR50 Appendix A "riterion 15.

The Nuclear Pressure Relief System is designed to afford adeguate additional marqin to assure that the design conditions of the "eactor coolant pressure boundary are not exceeded during any condition of normal operation, including anticipated operational occurrences.

(3) 10CPR50 Appendix A - "riterion 30.

The components of the Nucl ar Pressure Relief System are designed, selected, fabricated, erected and tested to the highest, practical, current industrial standards. The System is Rev. 22, 4/81 7.7-78

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SSES-"SAR tone selector switch, area selector switch, message tape recorder, river warning speakers'and monitors, and an outdoor roof siren. This system supplements "he radiation monitoring systems described in Chapter 12.

During emergen"y conditions the plant operator ac+ivates the system by selecting the designated ala m and area to be covered.

The. alarms and instructions are broadcasted v'a he PA system page lines to all speakers in selec+ed areas throughout tJ e plant. Durinc an emergency the night time mute function of outdoor speakers will be ove ridden. The r'er warning speakers have independent amplifiers with output monitor nc in the control room~

The operator switches the system to of, after confirmation of normal conditions. The preferred power for the EVAC system is supplied from Unit 1 vi..al ac bus, and the alterna+e power is fed from Unit 2 vital ac bus. During Unit 1 opera+ion while Unit 2 is under construction, power to the EVAC system is fed from he Unit 1 computer UPS bus. The preferred power for the roof siren is supplied from Unit 1 plant 125 V dc bus and the alternate power is fed from Unit 2 plant 125 V dc bus. During Unit 1 operation while Unit 2 is in construction stage, the alternate power to the roof siren is fed from a separate 125 Vdc bus of Unit 1. {refer to Subsections 8.3.1. 8 and 8.3.2.1.1.1) .

9.5.2.2.5 Security Communication and. Alarm System Refer to the Suscuehanna SES Security Plan For a description of the Security Communications System.

9.5 2.2.6 .Portable Communication System Onsite portable radio communication systems are described in the Susquehanna SES Security Plan and in the Susquehanna SES Emergency z a~.

9 5.2 .2.7 System Evaluation System design considerations include diversity and operational reliability. The in-Plant communication systems are provided with reliable and redundant power supplies for uninterrupted communications between all areas of the Plant.

Rev. 22, 4/81 9. 5-30

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SUSQUEHANNA STEAM ELECTRIC STATION EIC.

UNITS 1 AND 2 L. JOO,.,I ~4 OOCCOCI Oa 114!r FINAL SAFETY ANALYStS REPORT tt C 4'EOO OI r akco. t CONOIOILIC P 6 XD Ctrati pa 4 LIQUID RADNASTE PROCESSING FIGURE 11.2-10

SSES-FSAR 13 5 PLANT PROCEDUR ES 13 5. 1 ADNINISTRATIVZ PROCEDURES All safety-related operations at Susquehanna Steam Electric Station Units 1 6 2 are conducted in accordance with detailed, written and approved procedures. Plant personnel receive training in the use of appropria te procedures and the procedures are made available to them at all times.

13 5. 1. 1 Procedure Conformance Procedure topics follow the guidance specified by applicable portions of Regulatory Guide 1 33, Revision 1 and procedures aro prepared following the guidance provided by ANSI V18.7-1976.

13-5 1.2 Pre~aration of Procedures Procedures are prepared by the plant staff, support organizations or contract organizatio'ns under the direction of the Supe visor of Operations, Supervisor of Maintenance, Technical Supervisor, Health Physics Supervisor, Quality Supervisor, Personnel and Administrative Supervisor, and Security Supervisor. The plant procedure categories and a typical schedule for procedure preparation are shown on Figure 13.5 Review of safety-related procedures  !

use and changes thereto, is performed by the Plant Operations Review Committee (PORC} and approved by the Superintendent of Plant as described. in Section 13. 4. In addition, functional'nit procedures will be reviewed by Nuclear Quality Assurance.

Procedures are periodically reviewed to determine necessary or desirable if changes are Applicable procedures are reviewed after significant system or equipment modification, and following an unusual incident,"such as a hazardous condition, an unexpected transient, a significant operator error, or equipment malfunction where the procedures contributed to the cause of the incident, or were inadequate in mitigating the effects of the incident.

When an operation is temporarily altered in such a manner that portions of an existing procedure do not apply, then the existing procedure may be temporarily changed. Temporary changes to Rev. 22, 4/81 13 5-1

MOHTNS PRIOR TO FUEL LOADING 34 32 30 28 26 24 22 20 18 16 14 12 10 8 6 4 2 PROCEDURES ADMIHISTRATIVE ALARM RESPONSE CHEMISTRY EMERGENCY EMERGEHCY PLAH ENVIRONMENTAL SURVEILLAHCE FUEL NAHDLIHG GEHERAL PLAHT HEALTH PHYSICS CD IHSTRUMEHTATIOH A CONTROL MAINTENANCE CD MATERIAL COHTROL OFF-HORMAL OPERATING GUALITY RADWASTE MAHAGEMEHT REACTOR EHGINEERIHG RECORDS RELAY CALIBRATION SECURITY SPECIAL EVENTS SURVEILLAHCE TEST D TRAIHIHG Q z m l

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SSES-FSAR condition arise, the plant operating staff shall take whatever action is necessary including, but not limited to, stopping the test in order to restore safe plant conditions. During startup testing, the plant operating staff is specifically responsible for compliance with operating technical specifications, and compliance with the provisions of the operating license.

14.2 '.2 Test Prere uisites Specific test prerequisites are identified in each preoperational test procedure. The test director verifies that each prerequisite is completed and properly documented prior to signoff in the official test copy of the procedure. If a prerequisite in a preoperational test cannot be satisfied, the test director will list the prerequisite as a test exception to the Preoperational Test.

As a prerequisite to preoperational testing, proper operation of each alarm loop is verified and listed in an appendix to the test. During the preoperational test, system parameters are varied and interlocks are tested which cause alarms to actuate.

Those alarms which are actuated during the course of the test will be documented in the body of the preoperational test.

14.2.4.3 Procedure Hodifications Tests are conducted in accordance with approved procedures. Zf necessary, these procedures may be modified to complete testing. Such procedure modi-fications are documented on a test change notice form. Xn addition to generation of a test change notice form, the test dizector marks up the official test copy of the procedure and init:als/dates the change.

Review and approval for test change notices on preoperational test procedures is provided by the TRB.

Test change notices for startup test procedures shall be initialed/dated by an on-shift licensed senior operator in addition to the test director. Review and approval for test change notices on startup test procedures is provided by the PORC.

Preparation, review and approval activities aze accomplished before or after performance of associated testing based on the follow'ng criteria:

a) Non<<Intent Changes For procedure modifications that do not change acceptance criteria and do preserve the intent of the test, the test change notice may be approved after performance of associated testing.

4 b) Intent Changes i For procedure modifications that alter the acceptance criteria or the intent of the test, the test change notice is approved before performance of associated testing.

Rev. 22, 4/81 14.2-12

SS ES-FS AR information will be sorted and reported for a period of two years prior to fuel load on the first unit. The Manager-Nuclear Support is addressed in Subsection 17.2.1.

14. 2. 9 TRIAL US OF PLANT OPERATING AND EMERGENCY PROCEDURES The adequacy of Plant Operating and Emergency Procedures will be confirmed by trial-use during the Initial Test Program. Those procedures that do not require nuclear fuel are confirmed adequate to the extent practicable during the Preoperational Test Program. Those procedures that require nuclear fuel are confirmed adequate to the extent practicable during the Startup Test Program.

The plant operating staff is responsible for confirmation of operatinq and emergency procedures. The Superintendent of Plant is responsible for ensuring that comments/changes identified during confirmation are incorporated in finalized procedures.

It is not intended that preoperational test procedures explicitly incorporate or ref erence plant operating and emergency procedures. These tests are intended to stand on their own since they are not necessarily compatible with configurations and conditions required for confirmation of facility operating and emergency procedures. Startup test procedures will'ncorporate and reference plant operating and emergency procedures to the extent practical.

14-2-10 ~ INITIAL-FUEL- LOADING AND INITIAL CRITICALITY Initial fuel loading is accomplished in accordance with startup test procedure, accomplished in ST-3 Fuel Loading Initial criticality is accordance with startup test procedure ST-4, Pull Core Shutdown Margin. These procedures comply with the general guidelines and regulatory positions contained in Regulatory Guide 1.68 (Revision 1, January 1977). Test abstracts establishing the objectives, prerequisites, test method, and acceptance criteria for these procedures are presented in Subsection 14.2. 12.

14 2- 11 T>ST cd PROGRAM SCHEDULE The Preoperational Test Program is scheduled for 15 months duration on the Unit and Common components and for 12 months 1

duration on the remaining Unit 2 components..(See Figure 14.2-4a Rev. 22, 4/81 14. 2-19 ~ '

SSES-FSAR (P30.1) Control Structure HSV S stem Prep erational Test Structure Hav System and its interlocks inside the control structure building to demonstrate this system's ability to maintain a positive pressure above atmospheric during normal operation and high radiation signal when the emergency outside air supply mode is running. To demonstrate the ability of the Control Structure HGV to isolate before chlorine reaches the isolation dampers when chlorine is detected in the outside air intake.

over to the ISG. Required instruments are calibrated and controls are operable. The Control Structure Chilled Water System, Instrument Air System and turbine building vent are available. Required'lectrical power supply systems are available.

Test Method - The system operation is initiated manually and fan performance, damper operations and heating element operation are determined. The differential pressures with respect to outside atmosphere .are measured. Required controls are operated'or simulated signals are applied to verify the emergency filter operation on high radiation signal, automatic recirculation on high chlorine signal, system manual isolation and other system interlocks and alarms.

Acce tance Criteria - The system performance parameters are in accordance with the applicable design documents.

(P30.2) Control Structure Chilled Water S stem Prep erational Test Structure Chilled Water System to provide chilled water flow to Control Structure Heating/Ventilating Units and Control room floor and computer room floor cooling units.

to perform this test and the system is turned over to the ISG.

Required instruments are calibrated and controls are operable.

The Service Water System, Emergency Service Water System, and Instrument Air System are available. Required electrical power supply systems are available.

Test Method - The system is operated to demonstrate chiller operation and chilled water pump performance. Required controls are operated or simulated signals are applied to verify automatic alignment of the system under emergency conditions (start of emergency condenser water recirculation pump) and other system interlocks and alarms.

Rev. 22, 4/81 14. 2-3l,

SSES"FSAR Test Method - The battery performance test is manually initiated by connecting the battery bank to the Resistor I.oad Bank and discharging the batteries at a constant current for a specified period of time.

The Battery Service Test is manually initiated by connecting the battery bank to the Resistor Load Bank and simulating, as closely as possible, the load the batteries will supply during a Design Base Accident.

Then the battery charger is connected to the batteries and the distribution panels to verify that they can equalize charge the batteries while simultaniously providing power to the normal plant loads. The battery charger is also connected to the Resistor Ioad Bank and current is increased to its maximum rating with the charger isolated from its associated battery bank.

Alarms are simulator and verified to operate properly.

Acce tance Criteria - The batteries can satisfactorily deliver stored energy for the specified amount of time as required for the performance and service tests. The battery chargers can deliver rated output, also, that they can charge their associated battery bank from minimum voltage to a fully charged state in a specified amount of time while simultaneously supplying normal plant loads. The alarms operate at their engineered setpoints and annunciate in the control room.

(P76.1) Plant Leak Detection S stem Prep erational Test Test Ob'ective - 'To demonstrate the operability of the Plant Ieak Detection System.

to perform this test and the system is turned over to the ISG.

Required instruments are calibrated and controls are operable.

Required electrical power supply systems are available.

Test Method - Sump levels will be varied (if practicable) or simulated signals are applied to level sensors to verify the leak

'etection system alarms'cce tance Criteria - The system performance parameters are in accordance with the applicable design documents.

Rev. 22, 4/81 14.2- 49

SSES-FSAR

3) That all warning signals are working per design intent.

4) The capability of the crane to operate in a designated area in accordance with design requirements.

over to the ISG. Required electrical power supply systems are available and controls are operable. Required loads are available to perform load testing of this crane.

Test Method - The lighting system for the crane is energized and observed for proper operation. The bridge and the trolley are speed-tested in both directions. Current and voltage readings are taken in both directions. The proximity switches are tested for both the bridge and the trolley including trolley movement restriction switches in zones A, B, and C.

The main hoist and the auxiliary hoist are speed-tested traveling up and traveling down. Current and voltage readings are taken in both directions. All limit switches are tested. A loss of power situation is created for both hoists to check the brakes ability to hold without power. An overspeed test is simulated for each hoist. The main hoist load limit switch is also tested.

The above listed tests are run from the pendant pushbutton control system. Operability of the crane is also demonstrated from the cab and by 'radio control. The anticollision system is tested and the crane power source is verified.

Acce tance Criteria - The system performance parameters are in accordance with the'pplicable design documents.

(P100.1) Cold Functional Test capable of operating on an integrated basis in normal and emergency modes, to demonstrate that adequate power supplies for the class IE equipment will exist-completed and plant systems are ready for operation on an integrated basis.

Test Method - Emergency Core Cooling Systems (RHR 6 Core Spray) are lined up in their normal standby mode. The plant electrical system is lined up per normal electrical system lineup (For Unit l this lineup may be different than the lineup for two unit operation). Loss of coolant accident signals are initiated with and without a loss of offsite power. Voltages and loads are Rev. 22, 4/81 14.2" 55

SSES-FSAR UESTION 021.01 Provide the following additional information for the secondary containment:

(1) Show an appropriate plant elevation and section drawings,

, those structures and areas that will be maintained at negative pressure following a loss-of-coolant accident and that were considered in the dose calculation model; (2) Provide the Technical Specification limit for leakage which may bypass the Standby Gas Treatment System Filters, (e.g.,

valve leakage and guard pipe leakage); and, (3) Discuss the methods of testing that will be used to verify that the systems provided are capable of reducing to and maintaining a negative pressure of 0.25", e.g., within all secondary containment volumes.

RESPONSE

1) Following a loss-of-coolant-accident, all affected volumes of the secondary containment will be maintained at negative pressure. All these volumes are identified on Figures 6.2-24 thru 6.2-43 as ventilation zones I, II and III. Also see Subsection 6.5.3.2 for a discussion of the reactor building recirculation system.

2) See Technical Specification 3/4.6;.5.3 for the limiting conditions for operation and the surveillance requirements for the SGTS. All leakage into the secondary containment is treated by the SGTS.

Refer to subsection 6.2.3.2.3 for a discussion of containment bypass leakage.

3) The Standby Gas Treatment System (See Subsection 6.5.1.1) in conjunction with the reactor building recirculation system (see Subsection 6.5.3.2) and the reactor buildig isolation system (see Subsection 9.4.2.1.3) is provided to produce and maintain negative pressure within affected volumes of the secondary containment. Actuation and operation of the above systems will be used to verify that the negative pressure is established and maintained.

Each ventilation zone is provided with redundant negative pressure controllers. I,ow pressure side inputs (low pressure sensing elements) to these controllers are located as follows:

Ventilation Zone I- Access are of EL 749'-l (See Figure 6.2-28)

Ventilation Zone II- Access area of EL.749'-l" Rev. 22, 4/81 021.01-1

SSES-FSAR Ventilation Zone III - Refueling Floor, E1.818'-1" (See Figures 6.2-30 and 6.2-40).

The quantity of air exhausted from the secondary containment will be such that in each affected ventilation zone the negative pressure will be maintained. The interconnecting ductwork of the recirculation system will equalize the negative pressure throughout each zone.

Rev. 2, 9/78 021.01"2

SSES-FSAR UESTION 021.10 With respect to containment steam bypass for small breaks, indicate your compliance with our proposed Branch Technical Position "Steam Bypass for Mark II Containments," which is enclosed.

RESPONSE

A comparison of the Susquehanna SES design with your proposed BTP "Steam Bypass for MK II Coatainments" is presented below. The item numbers correspond with the items in the BTP.

l.a. B ass Ca abilit Containment Wetwell S ra s The wetwell spray system electrical instrumentation and controls supplied by GE meet the same ESF standards of quality, redundancy and testability as the RHR system, of which it is actuated.

a part. The system is manually controlled and The consequences of actuation of the wetwell spray on ECCS function are addressed in the response to Question 211.13.

l.b. Transient B ass Ca abilit Anal ses The calculation of maximum allowable steam bypass leakage for small steam breaks as presented in Section 6.2.1 of the Susquehanna FSAR complies with the intent of the proposed branch technical position; although it does not assume a normal plaat depressurization/shutdown time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The calculation assumes that the steam leakage is terminalted by some operator actioa (containment sprays, ADS) within 15 minutes after an abnormally high suppression chamber pressure is observed (830 psig). The maximum suppression chamber pressure expected during a IOCA, assuming all drywell air has been carried over and no steam leakage has occurred, is 25 psig. Significantly exceeding this pressure (to &30 psig) indicates a leakage situation and necessitates operator action. Further, the calculation conservatively neglects any containment heat sinks (pool surface, containment walls, etc.).

The method employed to calculate the maximum allowable steam bypass lakage flow characteristic (A/rgb) has been previously described in some detail in submittals to NRC questions on the Hatch l nuclear plaat. Briefly, it simply involves an end point type calculation of the mass of steam which can be added to the suppression chamber above 30 psig to give design pressure (45 psig), conservatively assuming all drywell air has been carried over the the suppression Rev. 22, 4/81 021.10-1

SSES-FSAR chamber and taking no credit for suppression chamber heat sinks/condensation. Knowing this mass of steam QM and assuming that the operator action will be delayed 10 minutes after observin'g the 30 psig, and that the action will require 5 more minutes to take effect (5t = 15 min. total),

the allowable lakeage rate m = Am/At can be calculated. The flow characteristic A/~k can then be calculated from M=A/ lv ps chp"(

g where bP is 'the pressure difference between the drywell and suppression chamber at quasi-steady flow (equal P<g/g H, where H = vent submergence). The result is an A/~k = .0 6 ft~ for Susquehanna.

2.a. FSAR Subsection 6.2.6.5 '.1 addresses this item.

2.b. FSAR Subsection 6.2.6.5.1.2 addresses this item.

2.c. FSAR Subsection '6.2.6.5.1.2 addresses this item.

3.a. The Susquehanna design meets the intent of this item. See Subsection 6.2.1.1.3.2.

With respect to compliance with the proposed Branch Technical Position "Steam Bypass of Mark II Containments," the following Susquehanna SRP position statement is respectfully provided:

Issuance of the Standard Review Plans (SRP) post-dates the Susquehanna construction permit by more than 2 years. Therefore, no attempt was made to design the plant to the requirements of the SRPs. The Susquehanna FSAR was prepared using Revision 2 of Regulatory Guide 1.70 as much as practical for a plant of its vintage, with assurance from NRC management that compliance with this Regulatory Guide assured submittal of all necessary licensing information.

As documented in a letter of August 5, 1977 from G. G. Sherwood to E. G. Case of the NRC, the SRPs constitute a substantial increase in the information required just to describe the degree of compliance of various systems. This increase in turn represents a substantial resource expenditure which is unjustified and which could cause proj ect delays if these projects. As stated in the, reference letter, General required of Rev. 22, 4/Sl 021.10-2

SSES-FSAR Electric (and PPM) believes that SRPs should be applied to FSARs only to the extent that they were required in the FSARs.

PPGL and General Electric believe the above position, which is the essence of a directive from Ben C. Rusche, Director of Nuclear Reactor Regulation, to the NRC staff dated January 31, 1977, is the appropriate procedure for review of the Susquehanna FSAR.

Rev. 22, 4/81 021.10-3

SSES-FSAR UESTXON 021.21 He are aware that revision 3 to the DFFR is to be submitted to this Summer and that Revision 2 which is now referenced is out-of-date, as it does not adequately reflect the status of current pool dynamic loads. Discuss how the DAR will be updated to reflect this status and discuss any other reports you intend to submit to document your plant design.

RESPONSE

PPGL is working with the other Mark II owners to develop methodologies, analytical programs and test data which will provide improved definitions of hydrodynamic loads. This effort has resulted in Revision 3 to the DFFR, and is expected to result in further revision to that report. lt is presently being revised to reflect the current position of the Mark XI owners.

Future revisions to the DFFR are expected to have no effect on the SSES DAR, since plant specifics as well as generic Mark XI methodologies applicable to SSES will be incorporated into the DAR.

The DAR has been updated to reflect the current design assessment methodologies used at SSES.

Rev. 22, 4/81 021.21-1

SSES-PSAR Identify all openings provided for gaining access to the secondary containment, and discuss the administr'ative controls that will be exercised over them. Discuss the instrumentation to be provided to monitor the status of the openings and whether or not the position indicators and alarms will have readout and alarm capability in the main control room.

RESPONSE

1) Secondary Containment Access Openings:

Door Nos. Elev. Col. Coordinates Security Monitored 101 670 U/29 Yes 102 670 U/37.4 Yes 103-0 670 U/20.6 Yes 104-0 670 U/29 Yes 119A 676 P/20.6 Yes 120A 676 P/37.4 Yes 571-0 818 P/32 Yes Roof Hatch 8 Elev. 872, coordinates: P/37.4 (Security Monitored)

2) Doors 5119A, 120A and 571-0 provide access into the secondary containment through the use of card reader/cipher keyboard control.

Doors 101, 102, 108-0, 104-0 and the roof hatch (54001) will not normally be used to gain access into the secondary containment.

All transactions will be logged into the Security Data and Management System (SDMS). All alarms generated will annunciate at both the Security Control Center (SCC) and Alternate Security Control Center (ASCC). The plant control room will not have a readout or alarm capability. Both the SCC and ASCC are, however, manned continuously 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day.

Instrumentation to control and monitor the status of secondary containment is described in Chapter 7.0 of the Susquehanna SES Physical Security Plan.

Rev. 22, 4/81 021.31-1

SSES-FSAR Subsection 4.2.2.2 of the DAR states that, the chugging loads on submerged structures and imparted on the downcomers will be evaluated later. .Provide the present status of these evaluations and the schedule for your submission of the completed evaluation.

RESPONSE

The calculation of submerged structure loads due to chugging will use the improved chugging load methodology developed under Mark IZ Owners Group Task A16. The appropriate design sources will be used with the Green's function solution for the SSES annular containment to provide the pressure distribution in the suppression pool. The pressure around a structure will be integrated to determine the net pressure load on the structure. A description of this methodology and verification will be included in the DAR. The chugging sources used will be developed from the pressure time histories provided by KWU for the design assessment (see SSES DAR, Section 9.5.3).

The downcomer has been assessed for the chugging loads and the results will be incorporated into the DAR. The other submerged structures are now being evaluated.

We expect completion'f this evaluation in April of 1981.

Rev. 22, 4/81 021.71-1

SSES-FSAR Provide the information previously requested in 020.44 regarding loads resulting from pool swell waves following the pool swell process or seismic slosh. Discuss the analytical model and assumptions used to perform these analyses.

RESPONSE

The analytical method of calculating the loads resulting from seismic slosh and the assumption used are described in a writeup to be included in the OAR. This information will be submitted in April 1981.

Rev. 22, 4/81 021.73-1

SSES-FSAR Discuss the applicability of the generic supporting programs, tests and analyses to SSES design (i.e., FSI concerns, downcomer stiffners, downcomer diameter, etc.)

RESPONSE

A complete description of the GKM-IIM test program, test results and evaluation of the test data is provided in Chapter 9.0 of the Susquehanna SES DAR. The GKM-IIM tests were structured to be as prototypical of the Susquehanna SES plant configurations as was practical. As such, concerns related to FSI, downcomers stiffnessg downcomer diameter, etc., are fully addressed.

Rev. 22, 4/Sl 021.75"1

SSES-FSAR Provide the time history of plant specific loads and assessment of responses of plant structures, piping, equipment and components to pool dynamic loads. Identify any significant plant modifications resulting from pool dynamic loads considerations.

RESPONSE

Time history information for LOCA loads can be found in SSES DAR, Section 4.2. Similar information due to SRV actuation can be found in SSES DAR, Section 4.1. In addition, the plant specific LOCA and chugging load definition developed from the GKM II-M test program can be found in Subsection 9.5.3. This load definition will be used to evaluate the conservatism of the DFFR LOCA load definition developed from the GKM II-M test program can be found in Subsection 9.5.3. This load definition will be used to evaluate the conservatism of the DFFR LOCA load definition and is scheduled for submittal in Revision 5 of the SSES DAR (March, 1981).

Assessment of the piping to pool dynamic loads is not completed.

PPGL interprets this question as requiring:

a) Response of piping in the wetwell to pool dynamic time history loads.

b) Response of piping in the drywell, wetwell and reactor building to response spectra due to SRV and LOCA loads.

Summary of the results of piping analysis will be provided in the DAR upon completion of piping analysis in May of 1981.

Modification of plant design to date a) Addition of quenchers b) Design changes in platform, vacuum breakers, and recombiner Support beams by raising them out of the pool swell zone.

c) Redesign of downcomer bracing system d) Added 60 reinforcing bars in each suppression chamnber.

e) Added embedments and anchor bolts in suppression chamber walls and diaphragm slab.

f) Diaphragm slab reinforcements changed from'5 to 90 to increase uplift loadings acceptance.

g) Significant number of pipe supports added or modified.

Rev. 22, 4/81 021.76-1

SSES-FSAR Provide figures showing reactor pressure, quencher mass flux and suppression pool temperature versus time for the following events:

(1) A stuck-open SRV during power operation assuming reactor scram at 10 minutes after pool temperature reaches 110 F and all RHR systems operable; (2) Same as event (1) above except that only one RHR train available; (3) A stuck-open SRV during hot standby condition assuming 120 F pool temperature initially and only one RHR train available; (4) The Automatic Depressurization System (ADS) activated following a small line break assuming an initial pool temperature of 120 F and only one RHR train available; and (5) The primary system is isolated and depressurizing at a rate of 100 F per hour with an initial pool temperature of 120 F and only one RHR train available.

Provide parameters such as service water temperature, RHR heat exchanger capability, and initial pool mass for the analysis.

RESPONSE

The Susquehanna unique SRV mass and energy release analysis is presented in Appendix I of the DAR.

Rev. 22, 4/81 021 '7"1

SSES-FSAR With regard to the pool temperature limit, provide the following additional information:

(1) Definition of the "local" and "bulk" pool temperature and their application to the actual containment and to the scaled test facilities, if any; and (2) The data base that support any assumed difference between the local and the bulk temperatures.

RESPONSE

The terms "Local" and "bulk" temperature are used as defined in Subsection III.C.l.a of NUREG 0487, "Mack II Containment Lead Plant Program Load Evaluation and Acceptance Critera", United States Nuclear Regulatory Commission, October 1978.

Because of the design features of quenchers and their orientation in the suppression pool (as discussed in the SSES DAR, Subsection 8.5.5),

the differences between "local" and "bulk" pool tempoeratures are expected to be small. Therefore, the difference should not exceed the value which was previously derived for ramshead discharge devices in Mark I plants (10'). It is intended to verify the numbers using data from in-plant tests which are presently under preparation for LaSalle and Zimmer.

Rev. 22, 4/81 021.78-1

SSES-FSAR uestion 021.79:

For the suppression pool temperature monitoring system, provide the following additional information:

(1) Type, number and location of timperature instrumentation that will be installed in the pool; and (2) Discussion and justification of the sampling or averaging technique that will be applied to arrive at a definitive pool temperature.

RESPONSE

(1) Please refer to revised Section 7.6.1b.l.2. Susquehanna SES has completed evaluation of the suppression pool monitoring criteria as defined in NUREG-0487 and has developed a basic system as follows:

o Number and Location of Tem erature Instruments: 20 remote temperature detectors (see figure 021.74-35) in each suppression pools

-16 remote temperature detectors located just below the min.

water level and arranged to provide 2 each on 8 locations around the pool.

-4 remote temperature detectors (see Figure 021.74-35-TE's 15769, 15761,15756, 15751) distributed around the pool at "Q" center-line location o ~T e: Class IE Instrument-Divisionalized with one from each location in each division, except for 4 remote temperature detectors at the "g" centerline. All sensors will be redundant, Seismic Category I and supplied from onsite emergincy power.

(2) The technique issued to arrive at an average, or bulk, pool temperature is conservative due to the placement of the 16 pool temperature detectors. These 16 detectors are evenly distributed near the pool surface, where the hottest water will rise Rev; 22'. 4/81 021.79-1

SSES"FSAR Table 7.2-4, Design Basis Setpoints, was deleted in Revision 11.

Several sections still refer to data contained in that table.

Several references are made to design basis setpoints previously listed in Table 7.2-4. This table has been intentionally left blank. Please clarify this discrepancy.

RESPONSE

Table 7.2-4 was deleted because the information thereon has been incorporated in the plant Technical Specifications. Some information from Table 7.2-1 and all the information from Tables 7.2-5 and 7.2-6 has been deleted from Section 7.2 and is also contained in the Technical Specifications as the appropriate single point of reference for this data. Various discussions in Section 7.2 have been revised by appropriately referencing the Technical Specifications rather than the deleted tables.

Rev. 22, 4/81 032.52"1

SSES-FSAR Discussion of the Emergency Core Cooling Systems and the associated tables are incomplete and inconsistent. Correct and clarify the following:

1) The same instruments are used for Reactor Vessel low water level and Primary Containment high pressure for many ESF systems. The specification shown for these instruments in Tables 7.3-1 through 7.3-5 are not consistant. Correct trip settings, ranges, and accuracies shown for these instruments.

2) These tables have allotted columns for instrument response times and margins (of trip setting) to meet requirements of IEEE 279-1971 Section 3, but most data has been omitted.

Response times should indicate minimum and/or maximum where applicable.

3) Table 7.3"1 has omitted all specifications for the Turbine overspeed instrument.

4) Figure 7.3-5 has several errors:

o It does not show two ADS logics as indicated in 7.3.l.la.,1.4.4.

o Referenced Figure 7.3-16 does not exist.

o It does not show low pressure interlocks to LPCI and CS required to initiate ADS as indicated in 7.3.l.la.l.4.4.

5) Table 7.3-2 indicates only one reactor water level setpoint (-149 inches) for the ADS. Section 7.3.1.1a.l.4.4 indicates two level setpoints, a low and a lower water level.

6) Use of level swtiches with a range of -150"/0/+60" to initiate ADS and CS action with trip settings at -149 does not seem like conservative design. Justify the use of this range for this application. Discuss accuracy of the trip setting and how it is affected by normal and accident environmental conditions and long term drift.

7) Why are two ranges shown for LPCI pump discharge pressure (10-240 psig and 10-260 psig). Range shown for this instrument in Table 7.3-4 is10-240 psig only.

8) Section 7.3.1.1a.l.4.5 on ADS Bypasses and Interlocks indicates that it is possible for the operator to manually delay the depressurizing action and states "This would reset Rev. 22, 4/Sl 032.54"1

SSES-FSAR the timers to zero seconds and prevent depressurization for 105 seconds." Table 7.3-2, Figure 7.3-8 Sht. 3 and Table 6.3-2 all indicate a time delay of 120 seconds. How is a time delay of 105 seconds achieved?

9) Explain why two ranges (50-1000 psig and 50-1200 psig) are listed for the Reactor Vessel Low Pressure instrument in Table 7.3-3.

10) Instrument ranges for pump discharge flow, Table 7.3-3, and pump minimum flow bypass, Table 7.3-4, are specified in inches of water but trip settings are in gpm. Supply ranges for these flow instruments in gpm.

Table 7.3-9 HPCI System Minimum Numbers of Trip Channels Required for Functional Performance does not agree with Table 7.3-1 HPCI Instrument Specifications. Table 7.3-8 does not list HPCI pump high suction pressure or Turbine Overspeed as shown in Table 7.3-1. Table 7.3-8 lists two items, HPCI pump flow and HPCI pump discharge flow, not shown in Table 7.3-1.

12) Table 7.3-4 Low Pressure Coolant Injection - Instrument Specifications does not agree with Table 7.3-10 Low Pressure Coolant Injection System Minimum Number of Trip Channels Required for Functional Performance. Table 7.3-10 does not list Reactor low pressure or Pump discharge pressure as shown in Table 7.3-4. Table 7.3-10 lists several trip channels which are not shown in Table 7.3-4. These include Reactor vessel low water level inside shroud, Reactor vessel low flow, Primary containment high pressure, and Reactor vessel low water level (Recirculation Pumps).

13) Table 7.3-11 Core Spray System Minimum Numbers of Trip Channels Required for Functional Performance is incomplete.

It does not list Pump Discharge Flow as shown in Table 7.3-1.

RESPONSE

Tables 7.3-1 thru 7.3-4 have been revised to include all appropriate instrument functions and the number of channels provided. The trip settings and response time information has been deleted, and is provided in the Technical Specifications. Tables 7.3-8 thru 7.3-11 are deleted, with appropriate number of channel information incorporated into Tables 7.3-1 thru 7.3-4. Revisions to Table 7 '-5 have been submitted with the response to Question 032.55.

2. The instrument response times and margins (of trip settings) are included in the Technical Specifications. The data in Rev. 22, 4/Sl 032.54"2

SSES-FSAR the Technical Specifications is intended to also satisfy the requirements of IEEE 279-1971, Section 3.

3. The HPCI turbine overspeed trip is a mechanical device, which is integral with the turbine. See Section 6.3, for discussion of the HPCI turbine. The overspeed trip setting and accuracy information is provided in the Technical Specifications.

4, Figure 7.3-5 is revised to show a simplified picture of the ADS and LPCI/CS initiation logic. The" ADS division I and II Logics, discussed in revised Subsection 7.3.l.la.l 4-4 and shown in detail by Figure 7.3-8 sheet 3, are identical and energizing either will initiate ADS. Therefore they are shown twice in Figure 7.3-5. Relating the simplified picture in Figure 7.3-5 to the detailed one in'Figure 7.3"8, the left branch corresponds to logic A in Div. I (or B in Div. II) and the right to logic C in Division I (or D in Div. II). A note has been added,to Figure 7.3-5 to clarify the separate logics for Div. I and Div. II. The reference to Figure 7.3-16 contained on Figure 7.3-5 is erroneous.

The correct reference Figure for LPCI logic is Figure 7.3-10, RHR FCD. The low pressure interlocks for pumps (CS and RHR) have been added to Figure 7.3-5.

5. The revised Table 7.3-2 includes an appropriate entry for .

ADS initiation, with action caused by two signals, one each from the reactor water level Ll, and reactor water level L3.

Both signals are required before ADS is automatically initiated. The set point for this action is provided in the Technical Specifications.

6. The instrument trip settings have been removed from the tables of Chapter 7 and included in the Technical Specifications'he level switch trip setting of -149 inches for ADS and CS will be changed and will be within the proper accuracy and range of the instrument. The trip setting accuracy related to abnormal operating temperature within the drywell is discussed in the response to question 032.59. Instrument drift is included in developing the instrument set points.

7. The LPCI pump discharge pressure permissive for the ADS has two redundant channels provided for each LPCI (RHR) pump.

However the instruments have identical ranges, so Table 7.3-2 has been revised to agree with Table 7.3-4.

8. The ADS timer setpoint found in Table 6.3-2 is an upper

/ limit. The correct setpoints (including margin) are provided in the Technical Specification. The proper time delay time is by mechanical adjustment of pneumatically operated time delay relay. The text of Subsection Rev. 22, 4/81 032.54-3

.SSES-FSAR 7.3 '.1a.l.4.5 has been revised to delete the actual numerical value. The 105 second time value is nominal, and was used to allow for the margin and tolerance of the device. The proper value is provided in the Technical Specification.

9. The two trip systems for CS have diverse instruments specified for reactor vessel and the same instruments are used in LPCI low pressure. Tables 7.3-3 and 7.3-4, as revised, give the instrument ranges for both trip systems.

The trip setting values are provided in the Technical Specifications.

10. The CS and LPCI (RHR) pump minimum flow bypass ranges are converted from differential pressure to flow on the revised Tables 7.3-3 and 7.3-4.

11. Table 7.3-1 has been revised to include HPCI pump minimum flow bypass and the HPCI pump flow controller signaling the HPCI turbine. The turbine overspeed trip is a mechanical device that is integral with the turbine, see Section 6.3.

The turbine overspeed instrument range has been added to Table 7.3-1. The number of channels provided is added to Table 7.3-1, and Table 7.3-8 is deleted. The minimum number of trip channels required have been added to the Technical Specifications.

12. The LPCI Table 7.3-4 has been expanded to include the instruments of the actual design and the number of channels provided. The margin and trip setting of Table 7.3-4 as well as Table 7.3-10 have been deleted.

13. The CS Table 7 '-3 has been revised to add the number of instrument channels provided, and margin, response time, and trip settings have been deleted. Table 7.3-11 has been deleted.

Rev. 22, 4/81 032.54-4

SSES-FSAR UESTION 040.2 The staff requires that the following qualification test program information be provided for all Class 1E equipment:

(1) Identification of Equipment including, (a) Manufacturer (b) Manufacturer's type number (c) Manufacturer's model number (2) Equipment design specification requirements, including, (a) The system" safety function requirements (b) An environmental envelope which includes all extreme parameters, both maximum and minimum values, expected to occur during plant shutdown, normal operation, abnormal operation, and any design basis event.

(c) Time required to fulfillits safety function when subjected to any of the extremes of the environmental envelope specified above.

(3) Test plan, (4) Test set-up, (5) Test procedures, (6) Acceptability goals and requirements, (7) Test results, (8) Identification of the documents which include and describe the above items.

(9) The information requested above shall be provided for at least one item in each of the following groups of Class 1E equipment.

(a) Switchgear (b) Motor control centers, (c) Valve operators (in containment)

(d) Motors (e) Iogic equipment Rev. 22, 4/81 040.2-1

SSES-FSAR (f) Cable (g) Diesel generator control equipment (h) Sensors (i) Limit switches (j) Heaters (k) Fans (1) Control boards (m) Instrument racks and panels (n) Connectors (o) Penetrations (p) Splices (q) Terminal blocks (10) In accordance with the requirements of Appendix B of 10 CFR 50, the staff requires a statement verifying: (a) that all Class 1E equipment has been qualified to the program described above, and (b) that the qualification information is available for an NRC audit.

RESPONSE

The qualification test program information for Class lE equipment is provided in the Susquehanna SES Environmental

(}ualification Report For Class lE Equipment submitted under separate cover.

Rev. 22, 4/81 040.2-2

SSES-PS AB start on the autostart signal and operate on standby for f ive minutes.

(d) Verifying that on loss of offsite power in conjunction with a safety features actuation signal the diesel generators start on the autostart signal, the emergency buses are energized with permanently connected loads, the auto-connected emergency (accident) loads are energized through the load sequence, and the system operates foz five minutes while the generators are loaded with the emergency loads.

(e) Verifying that on interruption of the onsite sources the oads are shed from the emergency buses in accordance with design requirements and that subsequent loading of the onsite sources is through the load sequencer.

(4) The voltage levels at the safety-related buses should be optimized for the full load and minimum load conditions that are expected throughout the anticipated range of voltage variations of the offsite powez source by appropriate adjustment of the voltage tap settings of the intervening transformers. Me require that the adequacy of the design in this regard be vezified by actual measurement and by correlation of measured values with analysis results.

Provide a description of the method for making this verification; before initial reactor power operation, provide the documentation required to establish that this verification has been accomplished.

RESPONSE

I. Refer to Figures 8.3-1, 8 3-2, 8.3-3 and 8.3-15 for the following discussion on undervoltage detection and transfer logic.

The primary bus transfer on loss of offsite power is initiated at the 13.8 kV startup switchgear. Each class 1E 4.16 kV switchgear buses provide transfer. Refer to Subsection 8.3theforbackup undervoltage discussion on bus arrangement and the interconnection of the offsite power supplies and the on-site distribution system Rev. 22, 4/81

~

~

040.6-3

SSES-ZS AR (1) Each 13.8 kV startup bus is provided with an offsite power supply and the capability of connecting to the second offsite power supply by the closing of the l3.8 kV tie breaker (breaker 52-10502) .

The undervoltage detection system at each 13.8 kV switchgear bus consists of (1) incoming feeder (offsite power supply) undervoltage -clays device 27AI, (2) bus undervoltage relay device 27A2, and (3) tie bus undervoltage relay - device 27A1.

{a) Device 27AX-initiates tripping of the incoming feeder.

Device 27AI is an instantaneous plunger type relay with pickup setting at 93.6 volts (78% of the rate 120 volts). Two independent single phase relays are used to monitor the A-B and 0-C phase voltages.

The incoming breaker is tripped on coincidence logic of the two undervoltage relays at 91 7 volts with 30 cycle time delay.

(b) Device 27A1-Provides the permissive for closing of tie breaker Device 27A1 is a long time induction disc type undervoltage relay set at 82 volts (68% of rated) and time dial 1/2. Two single phase relay are provided for monitoring the availability of the alternate offsite power supply at the 13. 8 kV level and provide a coincidence logic for the closing of the tie breaker (c) Device 27A2 initiates the bus transfer

)

Device 27A2 is a 3 phase instantaneous plunger type relay with three full wave bridge rectifiers. The relay is set to drop out at 30 volt (25% of rated).

Bus transfer is completed by the closing of the tie breaker (permissive by device 27A1).

2. Each 4.16 kV class 1E switchgear bus is provided with a preferred and an alternate (offsite) power supply and one diesel generator feeder as discussed in Subsection 8 3.1.3 The undervoltage detection and backup bus transfer on loss of offsite power or sustained degraded voltage on the bus is provided by (1) incoming feeder undervoltage relay-device 27',

(2) bus undervoltage relay - device 27A, and (3) degraded voltage protection relays-devices 27B1, 27B2, 27B3, and 27B4. The device settings for the Class IE bus undervoltage protection are summarized in the following Table 40.6-1.

Rev. 22,. 4(83 > 040.6-4

SSES-FSAR Device 27AI provides the permissive for closing of the incoming breaker Device 27AI is a single phase induction disc type relay set at 92 volts and time dial 1/2. This relay is used to monitor the availability of'the offsite power supply at the class lE 4.16 iv level.

(b) Device 27A initiates the bus transfer Device 27 A is a 3 phase instantaneous plunger type relay with three full wave rectifiers. The relay is set to drop out at 18 volt or 15% of rated bus voltage. The 4.16 kV bus transfer is initiated with a time delay of 10 cycles by tripping of the prefer incoming feeder breaker. The transfer is completed if the alternate offsite power supply to this 4.16 kV bus is available (permissive by device 27AI). In case the alternate offsite power is not available, the standby diesel generator is initiated to start with a 0.5 second delay.

(c) Devices 27B1, 27B2, 27B3, and 27B4 initiate bus transfer and undervoltage alarm. These undervoltage relays are solid-state, single phase with definite time delay (ITE 27D type definite long time).

The additional level voltage protection for each 4.16 kV Class IE bus is provided to assure that voltage levels at all Class IE distribution buses meet the minimum requirement of all safety related equipment.

In the event of loss of voltage on the 4.16 kV Class IE bus, the bus undervoltage relay (27A) initiates bus transfer per paragraph (b) above. In addition, relays 27Bl, 27B2, 27B3, and 27B4 provide back up protection for alarms and initiating bus transfer.

If a degraded voltage condition occurs on the 4.16 kV Class IE bus, with no LOCA signal present (see Figure 8.3-15), which is below the setting of relays 27B1 and 27B2, an alarm (coincidence logic) will be initiated after 10 seconds. The same relays will initiate the bus transfer after 30 minutes LOCA signals will bypass relays 27B1 and 27B2 or bus transfer will be blocked by LOCA. The 10 second time delay is provided to preclude spurious alarms. The 30~inutes time delay is provided for operators to initiate corrective actions.

These relays provide pre-alarm to alert the operator that "abnormal" voltage condition exists at the Class IE bus.

Rev. 22, 4/81 040.6-5

SSES-FSAR In addition, relays 27B3 and 27B4 will initiate an alarm and bus transfer after 17 seconds when the bus voltage is degraded below the setting coincident with an LOCA condition. These two relays are also connected in a coincident logic with time delay relays to preclude spurious tripping of the offsite power sources.

This protective scheme will force a loss of offsite power on the 4.16 kV Class IE bus on degraded bus voltage.

If the alternate offsite power is not available, the emergency diesel generator will be started automatically with a 0.5 second delay and connected to the respective bus within 10 seconds per section 8.3.1.4.1.

All bus undervoltage relays will initiate bus transfer, only when the bus is fed from the offsite power supplies. However, these relays will initiate undervoltage alarm even when the bus is energized by emergency diesel generator.

II. (1) Selection of all vol tage relay settings is based on the on-site distribution system load flow study and is verified by preopezational tests. The continuous operating voltage at each distribution voltage level is maintained at, + 10% of the rated voltage level over the entire transmission grid operating range.

Tripping of the offsite pover supply at the 13.8 kV level is accomplished by a coincidence logic of tvo independent'ingle phase undervoltage relays. The backup tripping of the same offsite power supply to the Class 1E 4 16 kV svitchgear is provided by a 3 phase full wave rectifiers type undezvoltage relay for minimizing nuisance tripping such as loss of a-..single control fuse in the detection circuit.. The total time delay allowed by restarting {starting) of class lE equipment after a DBA is 13 seconds as shown on'able 8.3-1. 10 seconds is reserved for diesel generator starting. Therefore, 3 seconds is allocated for voltage sensing and bus transfer. Pze-operating tests vill verify that the time delay on the bus transfer does not exceed the allowable time.

As discussed in (I) of above, offsite power supply zs automatically disconnected at the 13.8 kV level. If the transfer is not completed within the time delay of the Class 1E 4 16 kV bus transfer circuit, the offsite power supply is also disconnected at the 4.16 kV level. The undervoltage detection sensors and circuits are designed in accordance with IEEE std 279-1971 Rev. 22, 4/81 040.6-6

SSES-FSAR (2) All loads on each 4.16 kV Class 1E switchgear bus except the 480 volt load center ceder are shed on loss of power to the bus. Once the bus is re-energized, the

4) 4.16 kV Class lE loads are loaded in accordance with the 4( pre-set time delay. Load shedding and reloading of 4.16 kV class lE loads are repeated as discussed above whenever the bus becomes de-energized.

Refer to Chapter 16 for Technical Specification.

(4) Transformer tap settings ace selected for optional operating voltage levels for a11 loading conditions under the anticipated voltage variation of the offsite power supplies. The continuous operating voltage at each level is maintained within + 10% o rated. Pre-ope ational tests verify the actual voltage levels.

III. Relay Settings:

settings of undervoltage relays are determined in consideration The function and starting conditions of the full load, minimum load, and the largest motor voltage variations that are expected throughout the anticipated range of for the offsite power sources.

The following design criteria are used:

the minimum load condztxons (1) The maximum allowable voltage at no load or is 110% of the motor rated voltage.

running load condition xs 90/

(2) The minimum voltage under the maximum of the bus rated voltage.

(3) The minimum starting voltage is 80% of motor rated voltage.

See Table 40.6-1.

Rev. 22, 4/81 040.6-7

SSES-FSAR TABLE 40.6-1 SETTING TABLE (4KV BUS)

Voltage Time Device No. Function Alarm ~net tin ~nettin 27AI Permissive to close the Yes 95% 8 sec.

(preferred) preferred power incoming Breaker.

27AI Permissive to close the Yes 95% 8 sec.

(alternate) alternate power incoming Breaker 27A Initiate bus transfer. Yes 15% 10 cycles Trip the incoming closed breaker.

59/27 Bus over/under voltage Yes 110%/90% 10 sec.

(alarm only & located in load center) 27Bl Undervoltage alarm and Yes 95% 10 sec.

27B2 initiate bus transfer with time delay relays.

27B1X Time delay relays with No 30 min.

27B2X 27B1 & 27B2 to initiate bus transfer.

27B3 Initiate bus transfer No 93% 17 sec.

27B4 on LOCA condition Rev. 22, 4/81

SSES-FSAR QUESTION 040.32:

In section 9.5.2.2 you describe the plant communications system provided. It is noted that use of radio (portable and fixed) communications has been excluded. As part of the plant defense-in-depth concept, in the event of an accident or fire in an area where fixed communications systems cannot be used, we require (as a minimum) that portable communications equipment be provided at strategic work stations in the plant for use by personnel under such conditions.

RESPONSE

Refer to revised Subsection 9.5.2 and the response provided to question 281.13.

Rev. 22, 4/81 040.32-1

SSES-FSAR UESTION 40.95

1. Provide a table that lists all equipment including instrumentation and vital support system equipment required to achieve and maintain hot and/or cold shutdown. For each equipment listed:

a. Differentiate between equipment required to achieve and maintain hot shutdown and equipment required to achieve and maintain cold shutdown.

b. Define each equipment's location by fire area,

c. Define each equipment's redundant counterpart,

d. Identify each equipment's essential cabling (instrumentation, control, and power). For each cable identified: (1) Describe the cable routing (by fire area) 'from source to termination, and (2) Identify each fire area location where the cables are separated by less than a wall having a three-hour fire rating from cables for any redundant shutdown system, and

e. List any problem areas identified by item l.d.(2) above that will be corrected in accordance with Section III.G.3 of Appendix R (i.e., alternate or dedicated shutdown capability).

RESPONSE

The method of verifying safe-shutdown capability suggested in Q40.95 was considered. However, a more efficient and less time-consuming but equally effective method of review based on examination of each fire zone was chosen.

First, a list of systems required to shutdown the plant was developed.

Criteria included a loss of offsite power, all systems should be safety-related, no single failure (other than a single fire and its effects), and that manual operation and control post-fire were acceptable. See Table 40.95-1.

To show the redundant equipment and differentiate between equipment required to achieve and maintain hot shutdown and equipment required to achieve and maintain cold shutdown, Table 40.95-1 is divided into three groups of systems, categorized by their functions, as described below.

Group I consists of those systems required for both hot and cold shutdown. An example is the control rod drive manual scram circuits. Group I systems are further divided into two independent subsystems designated Division I and Division II. Divisions in any one Group I system must be single-fire isolated* from each other.

Rev. 22, 4/81 40.95-1

SSES-FSAR Group II consists of those systems required for hot shutdown. Several systems are listed t;ogether because of the interdependency of these systems, e.g.

diesel generators and auxiliaries. Again, these systems are further divided into Divisions I and II. All equipment and cables essential for Group II, Division I, must be single-fire isolated from all essential cables for Group II Division II systems. Hence, as an example, RCIC (Division I) and HPCI (Division II) must be single-fire isolated* from each other.

Group III consists of those systems required for cold shutdown. Again, Division I must be single-fire isolated* from Division II.

Those systems with containment isolation valves have a cross-divisonal circuit. This is necessary for diverse containment isolation function.

If the system, say HPCI, is Division II, the cross-division isolation valve circuits would be routed in their own separated conduits. Likewise, the RCIC system, Division I, the cross-divisional circuits would be routed in their own conduits. The cross divisional circuits of these two systems, will be single-fire isolated from each other and from both Divisions I and II up to the breaker.

Table 40 '5-2 is a specific component listing of those devices essential to the functioning of the systems in Table 40.95-1. Fire zone location for each device is also- listed. Unit 2 equipment for non-common systems differ only in that the prefix 1 is changed to 2 for both equipment number and fire zone.

The specific method of cable review is described below.

The Fire Protection Review Report analysis (Section 4.0) verifies that fires will be contained within the zone of origin. Each fire zone is reviewed individually. First, a raceway layout drawing is marked to show the divisionalization of the safety-related raceway. The minority division is identified and its raceway is listed. The term "minority division" refers to the electrical division which has fewer of its raceways routed through the fire zone in question. Actually, either division could be chosen for further examination, but the minority division represents the least effort.

The cables in all the listed minority raceways are checked, and any not connected to a safe shutdown system as given in Table 40.95-1 or to any of the components listed in Table 40.95-2 are deleted. All cable left is reviewed for its support of the system's safe shutdown function(s) and for the effects of failure caused by fire. This step leaves safe shutdown cabling that violates fire zone separation.

Each cable or component is then reviewed for applicable fire protection measures. The cable is then either rerouted or separation barriers and/or suppression and detection systems, as necessary, are provided.

• Single-fire isolated means either in separate fire zones or having the following fire-protection measures:

a) Fire/smoke detection is provided in all fire zones containing essential minority division safe shutdown raceway.

. Rev. 22, 4/81 40.95-2

FS A R-SS ES TABLE 40- 95-1 Systems Required For Shutdown GROUP I Systems Required for Hot 6 Cold Shutdown Control Rod Drive Manual Scram Circuits only Main Steam Isolation Valves (manual closure f unctions only)

Suppression Pool Temperature Mcnitorinq Reactor Pressure Vessel Instrumentation GROUP II Systems Required for Hot Shutdown Division I RCIC ADS ESH ESSW Pumphouse HVAC Diesel Generators and Auxiliaries Diesel Generator HVAC Containment Instrument Gas Division Il HPCI plus all Division II of these systems under Mode II, Division except RCIC.

GROUp III Systems Required for Cold Shutdown Division I RHR RHRSM ESQ ESSM Pumphouse HVAC Diesel Generators and Auxiliaries Diesel Generator HVAC Division II All Division II of above Rev. 22, 4/Sl

SSES-FSAR

2. Provide a table that lists Class 1E and Non-Class IE cables that are associated with the essential safe shutdown systems identified in, item 1 above. For each cable listed:

a. Define the cables'ssociation to the safe shutdown system (common power source, common raceway, separation less than Regulatory Guide 1.75 guidelines, cables for equipment whose spurious operation will adversely affect shutdown systems, etc.))

b. Describe each associated cable routing (by fire area) from source to termination, and

c. Identify each location where the associated cables are separated by less than a wall having a three-hour fire rating from cables required for or associated with any redundant shutdown system.

RESPONSE

a. Affiliated circuits are used in SSES in place of "associated" circuits which are defined in Section 8.1.6.ln paragraph 4) and 5). The separation/isolation between Class IE and non-Class IE cables are designed to minimize any failure in the non-Class IE equipment from causing unacceptable influences in the Class IE system.

b. The affiliated circuits are subjected to the same requirements as Class IE circuits. Refer to Sections 3.12.3.4 and 8.3.1.11.4 and Table 8.3-10 for cable routing requirements.

c. The affiliated cables are routed with their respective Class IE cables as described in Table 8.3-10. Therefore, the separation between the affiliated cables and the redundant Class IE cables, including those cables required for safe shutdown, is in accordance with Regulatory Guide 1.75. The .

response to Question 40.95 addresses the cable separation between redundant shutdown systems.

Rev. 22, 4/81 40.96-1

SSES-FSAR UESTION

3. Provide one of the following for each of the circuits identified in item 2.c above:

a The results of an analysis that demonstrates that failure caused by open, ground, or hot short of cables will not affect it's associated shutdown system,

b. Identify each circuit requiring a solution in accordance with section III.G.3 of Appendix R, or Identify each circuit meeting the requirements of section III.G.2 of Appendix R (i.e., three-hour wall, 20 feet of clear space with automatic fire suppression, or one-hour barrier with automatic fire suppression).

RESPONSE

a. An affiliated circuit may affect its associated shutdown system in two ways:

Affiliated circuit routed with shutdown circuit or in same enclosure:

A~nal aie: An open circuit of affiliated cable will not affect shutdown system because the Class IE cable and affiliated cable have the same qualified cable insulation. (see Table 9.5-1).

For shorting or grounding of affiliated circuits, refer to Section 8.1.6.ln paragraph 5) for the basis and methods for separation/isolation of Non-Class IE and Class IE circuits.

The worst credible event which could affect one of the redundant shutdown trains through the affiliated circuit is a fire involving a raceway containing both affiliated cable and its associated shutdown system cables. Assume in the worst case where these cables are all shorted together with 120 V ac, 125 V dc, 250 V dc, or 480 V ac cable due to a fire. (4 kV and higher voltage cables are routed in their own conduit).

The protective device(s) of the faulted circuits should be tripped to prevent further damage into the shutdown system. If the Class lE protective device does not trip, the shutdown equipment may be damaged, and therefore prevent the equipment from performing its shutdown function. However, failure of a Class lE device to trip must be considered a single failure, which is beyond the fire protection design basis. In order for this shutdown train, as designed, to fail due to fire, these multiple, independent, low probability events must happen simultaneously. This is considered extremely unlikely.

Rev. 22, 4/81 40.97-1

SSES-PSAR (2) Affiliated circuit sharing the same power supply of the associated shutdown circuits:

A~nal sis: Same as described in Section 8.1.6.1.n for separation/isolation of non-Class IE and Class IE circuits.

b. Rc. The affiliated circuits are subjected to the same requirements as Class IE circuits. The response to question 40.95 addresses this condition.

Rev. 22, 4/81 40.97-2

SSES-FSAR 5 ~ The residual heat removal system is generally a low pressure system that interfaces with the high pressure primary coolant system. To preclude a LOCA through this interface, we require compliance with the recommendations of Branch Technical Position RSB 5-1. Thus, this interface most likely consists of two redundant and independent motor operated valves with diverse interlocks in accordance with Branch Technical Position ICSB 3. These two motor operated valves and their associated cable may be subject to a single fire hazard. It is our concern that this single fire could cause the two valves to open resulting in a fire-initiated IOCA through the subject high-low pressure system interface. To assure that this interface and other high-low pressure interfaces are adequately protected from the effects of a single fire, we require the following information:

a ~ Identify each high-low pressure interface that uses redundant electrically controlled devices (such as two series motor operated valves) to isolate or preclude rupture of any primary coolant boundary.

b. Identify each device's essential cabling (power and control) and describe the cable routing (by fire area) from source to termination.

C. Identify each location where the identified cables are separated by less than a wall having a three-hour fire rating from cables for the redundant device.

d. For the areas identified in item c above (if any),

provide the bases and justification as to the acceptability of the existing design or any proposed modifications.

RESPONSE

We have reviewed the major reactor pressure boundary high pressure/low pressure interface valves per Branch Technical Position RSB 5-1. Using these criteria, check valves in series with motor operated valves (MOVs) are acceptable. A fire could open only the MOV. Many occurrences of this combination of check and MOV exist at SSES in the Core Spray, Feedwater, and Residual Heat Removal Systems, among others. Usually associated with the check valve is a pneumatic operator. This operator is for testing purposes only and can neither unseat nor prevent from seating the valve flapper when a differential pressure exists across the valve. Hence, a fire-caused failure of the solenoid actuators for the pneumatic operators on these check valves cannot cause the valves to open inadvertently and thus cannot degrade the reactor coolant pressure boundary.

Rev. 22, 4/Sl 40.99"1

SSES-FSAR In addition to the above, three pairs of valves per unit (six pairs total), all associated with the RHR System as high/low pressure interface valves, consist of two remotely operated valves in series. One pair of these valves per unit in the shutdown cooling suction line. The other pair are in the lines to each RHR heat exchanger for use in the steam condensing mode.

The valve numbers are given below:

Unit 1 HV-E-11 - 1F008/HV-E-ll-l F009 Shutdown Cooling Mode (motor operated)

PV-E-ll - 1F051A/PV-E-ll-l F052A Steam Condensing Mode (air operated)

PV-E-ll - 1F051B/PV-E-ll-l F052B Steam Condensing Mode (air operated)

Unit 2 HV-E-11 - 2F008/HV-E-ll - 2F009 Shutdown Cooling Mode (motor operated)

PV-E-ll - 2F051A/PV-E 2F052A'team Condensing Mode (air operated)

PV"E 2F051B/PV-E-ll - 2F052B Steam Condensing Mode (air operated)

The shutdown cooling suction valves are in separate divisions and are subject to the normal separation criteria. Also, the inboard valve is located inside the inerted containment where a fire can not be postulated. A cable-by-cable separation review was conducted; cables from both valves are not routed in any single fire zone other than the main control room and the Remote Shutdown Panels (RSP).

A reactor pressure vessel interlock prevents a shutdown cooling valve switch in the main control room from opening its valve whenever the vessel pressure exceeds the design rating of the downstream RER piping. A design change is underway to relocate the pressure interlock contact between the MCR and the RSP. The relay panels containing the pressure contacts are located in separated relay rooms. Hence, a fire or an operator mistake in either the MCR or RSP will not cause an overpressurization.

The steam condensing mode valves are interconnected by design for coordinated steam admission and pressure control and hence are not separated nor divisionalized. Should both valves be driven open by fire, adequate overpressurization protection exists via PSV-Ell"F055A 8 B to prevent rupture of the downstream RHR piping.

Rev. 22, 4/81 40.99-2

SSES-FSAR Figures 3.6-1 through 3.6-9 and 3.6-14 are indicated as "Later".

Provide a schedule for their inclusion in the FSAR.

RESPONSE

See revised figures 3.6-1 through 3.6-8.

Figure 3.6-9 has been intentionally left blank.

Figure 3 '-14 will be provided in the second quarter of 1981.

Rev. 22, 4/81 110.29-1

SSES-FSAR As required by 10 CFR 50.55a(g) we request that you submit your preservice and initial 20 month inservice testing program for pumps and valves. Enclosure 110-3 provides a suggested format for this submittal and a discussion of information we require to justify any relief requests.

RESPONSE

The preservice and initial 20 month inservice testing program for pumps and valves has been submitted under separate cover.

Rev. 22, 4/81 110.47-1

SSES-FSAR A review of the design adequacy of your safety-related electrical and mechanical equipment under seismic and hydrodynamic loadings will be performed by our Seismic Qualification Review Team (SQRT).

A site visit at some future date will be necessary to inspect and otherwise evaluate selected equipment after our review of the following requested information. The SQRT effort will be primarily focused on two subjects. The first is the adequacy of the original single-axis, single-frequency tests or analyses of equipment qualified per the criteria of ZEEE Std. 344-1971.

The second subject is the qualification of equipment for the combined seismic and hydrodynamic vibratory loadings. The frequency of this vibration may exceed 33 hertz and negate the original assumption of a components rigidity in some cases.

Attached Enclosure 110-4 describes the SQRT and its procedures.

Section V.2.A requires information which you should submit so that SQRT can perform its review.

Several of the BNR Hark ZI OL applicants have stated in their Closure Reports that equipment will be qualified for the SRSS combination of the hydrodynamic and seismic required response spectra (RRS) . Similarly, when qualified by analysis, the peak dynamic responses of the equipment to the hydrodynamic and seismic loads will be combined by SRSS. The combining by SRSS of either the RRS or peak dynamic responses for hydrodynamic and seismic loadings is not acceptable at this time.

To aid the staff in its review, provide a compilation of the required response spectra listed below for each floor of the seismic Category 1 buildings at your plant.

(1) the RRS for the OBE or SSE, whichever is controlling.

lf the OBE is controlling, explain why.

(2) the controlling hydrodynamic RRS (3) items (1) and (2) combined by SRSS (4) items (1) and (2) combined by absolute sum.

RESPONSE

The concerns raised by this question have been addressed in the SRQT submittals of December, 1980, January, 1981 and February, 1981.

Rev. 22, 4/81 110.50-1

SSES-PSAR QUESTION 121. 8:

~e will require that your inspection program for Class 1, Z and 3 components be in accordance with the =evise'ules in 10 CEH Pdr 50, Section 50.55a, paragraph (g) publ'shed in the Pebruary 12, 1976 issue of the ."-EDERAL REGISTER.

To evaluate your inspec-ion p "ogram, "he following minimum information is necessary ror our review:

(1) A preservice inspection plan to consis- of the applicable ASllE Code Edition and the exceptions to the Code requirements.

(2) An inservice inspection plan submitted within six months of anticipated commercial operation.

The preservice inspection plan will be revi..wed to support the safety evaluation report finding on compliance with preservice and inservice inspection requirements. The basis for the determination will be compliance with:

(1) The Edition of Section XI of the ASl}E Code stated in your PSAR or later Edit'ons of Section XI =eferenced in the FEDERAL REGISTER that you may elect to apply.

All augmented examinations established by the Commission when added assurance of structural reliability was deemed necessary. Examples of augmented examination requirements can be found in NRC positions on (a) high energy fluid systems in SRP Section 3.2, (b) turbine disk integrity in SRP Section 10.2.3, and (c) feedwater inlet nozzle inner radii.

Your response should define the applicable Section XI Edition (s) and subsections. If any examination requirements of the "-dition of Section XI in your PSAR can not be met, a relief request including complete technical justif ica tion to support your conclusion must be provided.

The inservice inspection plan should be submitted for review within six months of anticipated commercial operation to demonstrate compliance with 10 CFR Part 50, Section 50.55a, paragraph (g) . This plan will be evaluated in a safety evaluation report supplement. The objective is to incorporate into the inservice inspection program Section XI requirements in effect six months prior to commercial operation and any augmented Rev. 22, 4/81 121.8-1

examination requirements established by the Commission. Your response should define all examination requirements that you determine are not practical within the limitations of design',

geometry, and materials of construction of the components.

Attached are detailed guidelines for the preparation and content of the inspection programs and relief requests to be submitted for staff review.

RESPONSE

The inspection program for Class 1, 2 and 3 components has been provided (PLA-619, N. W. Curtis to B. J. Youngblood dated 1/27/81) .

Rev. 22, 4/81 121.8-2

SSES-FSAR UESTION 123.1 Pursuant to General Design Criterion 2, safety-related structures, systems and components are to be designed for appropriate load combinations arising from accidents and severe natural phenomena. With regard to the vibratory loads attributed to the feedback of hydrodynamic loads from the pressure suppression pool of the containment, the staff requires that safety-related mechanical, electrical, instrumentation and control equipment be designed and qualified to withstand effects of hydrodynamic vibratory loads associated with either safety relief valve (SRV) discharge of LOCA blowdown into the pressure suppression containment combined with the effects of dynamic loads arising from earthquakes.

The criteria to be used by the staff to determine the acceptability of your equipment qualification program for seismic and dynamic loads are IEEE Std.

344-1975 as supplemented by Regulatory Guides 1.100 and 1.92, and Standard Review Plan Sections 3.9.2 and 3.10. State the extent to which the equipment in your plant meets these requirements and the above requirements to combine seismic and hydrodynamic vibratory loads. For equipment that does not meet these requirements provide justification for the use of other criteria.

RESPONSE

I. BOP For Susquehanna Project, all BOP Safety related mechanical, electrical, instrumentation and control equipment located inside Primary Containment, Reactor and Control buildings, is being qualified for Seismic loads in combination with hydrodynamic vibratory loads associated with SRV discharge and LOCA blowdown. Although the SRSS method of combination of seismic and hydrodynamic loads is acceptable, for the project to be conservative, the loads are combined by absolute sum method. The cases which have deviations from the absolute sum method of combination will be identified in the qualification reports.

The criteria for the qualification of BOP equipment for seismic loads is described in Section 3.7b.3 of the FSAR. The criteria for load combinations and methodology for the design assessment and qualification of Safety related BOP equipment for seismic and hydrodynamic loads have been described in Sections 5 ' and 7.1.7 of the Design Assessment Report (DAR) Rev. 2. Basically the requirements of IEEE Std. 344-1975 as Supplemented by Regulatory guides 1.100 and 1.92 and SRP Sections 3.9.2 and 3.10 are covered in the criteria with the following exception for spatial combination of three components of dynamic motion as stated in Section 7.1.7.1.3 of the DAR. The criteria states "the response at any point is the maximum value

~

Rev. 22, 4/81 123.1"1

SSES-FSAR obtained by adding the response due to vertical dynamic load with the larger value of the responses due to one of the horizontal dynamic loads by the absolute sum method."

All Susquehanna BOP equipment is being qualified for the criteria discussed above.

II. NSSS LOAD COMBINATIONS:

These were transmitted to the NRC on 8/28/80 as Page 3 of Attachment N to PLA-536. This was in response to NRC Question 110.42.

IMPLEMENTATION OF LOAD COMBINATIONS:

The GE SQRT Program uses outputs from the GE Equipment Adequacy Evaluation Program which combines dynamic loads by SSES as accepted by the NRC in NUREG-0484.

The individual items associated with the load combinations are added as described below:

Steady State Events (e.g., Dead Load, Pressure) - Absolute Sum Time Varying Components (e.g., Maximum Seismic, Maximum Hydrodynamic)

- SRSS Components of Events (e.g., Maximum X-Load Due to Y-Earthquake) - SRSS Modal Response-SRSS, except for closely spaced modes where effects are combined by Absolute Sum, Double Sum, or Grouping.

Details for each item of equipment are contained in that equipment's Design Record File which is available for audit.

Rev. 22, 4/81 123.1"2

SSES-FSAR Provide the following information:

Two summary equipment lists (one for NSSS supplied equipment and one for BOP supplied equipment). These lists should include all safety related mechanical components, electrical, instrumen-tation, and control equipment, including valve actuators and other appurtenances of active pumps and valves. In the lists, the following information should be specified for each item of equipment.

(1) Method of qualification used:

a) Analysis of test (indicate the company that prepared the report, the reference report number and date of the publication).

b) If by test, describe whether it was a single or multi-frequency test and whether input was single axis or multi-axis.

c) If by analysis, describe whether static or dynamic, single or multiple-axis analysis was used. Provide natural frequency (or frequencies) of equipment.

(2) Indicate whether the equipment has met the qualification requirements.

(3) Indicate the system in which the equipment is located and whether the equipment is required for:

a) hot stand-by b) cold shutdown c) both d) neither (4) Location of equipment, i.e., building, elevation.

(5) Availability for inspection (Is the equipment already installed at the plant site?)

Rev. 22, 4/81 123.2-1

SSES-FSAR (ii) An acceptable scenario of how to maintain hot stand-by and cold shutdown based on the following assumptions:

(1) SSE or OBE (2) Loss of offsite power (3) Any single failure (iii) A compilation of the required response spectra (RRS) for all applicable vibratory loads (individual and combined if for each floor of the nuclear station under consideration.

required)

RESPONSE

The response to this question was submitted via PLA-627 (Curtis to Youngblood) dated February 5, 1981.

Rev. 22, 4/81 123.2-2

SSES-FSAR UESTION 123.3 Identify those items of nuclear steam supply system and balance-of-plant equipment requiring reevaluation and specify why reevaluation is necessary (i.e. because the original qualification used the single frequency, single axis methodology, because equipment is affected by hydrodynamic loads, or because both of the above conditions were present) for each item of equipment.

RESPONSE

Originally almost all Safety related BOP equipments for Susquehanna had been qualified for only Seismic loads. This equipment has been re-.evaluated due to the inclusion of new hydrodynamic (SRV 6 LOCA) loads, and are being re-qualified with respect to the criteria described in DAR Section 7.17. The qualification program for the BOP Safety related equipment is being executed in the following four phases.

Phase-I: uglification of E ui ment for Onl Seismic Loads:

The only known dynamic load at the time of execution of this phase of the program was Seismic loads. During this phase, the vendors supplying the equipment were required to qualify the equipment in accordance with the re q ui rem ents s pecxfx.ed xn FSAR Subsectx.on 3.7b.3.

Phase>>II: Evaluation for Combined Seismic and H drod amic (SRV 8 LOCA) Loads:

This phase was undertaken to evaluate if the existing Seismic qualification of all Safety related BOP equipment could be extended to the combined Seismic and hydrodynamic loads. The criteria used for the re-evaluation is described in DAR Section 7.1.7. The general problem areas identified during this evaluation and the proposed action to mitigate these problems are shown below.

123.3-1 Rev. 22, 4/81

SSES-FSAR PROBLEM ACTION Additional Hydrodynamic o Retest and/or Reanalysis.

Loads o Modifications to equipment or their Supports if required.

Flexibility of Equipment o Provide response spectre Support not considered considering support flexi-bility.

o Include Support Conditions during analysis or testing.

Inadequate Modelling o Correct during reanalysis.

Inadequate Testing o Retest o Qualification by analysis.

Phase III: Re uglification Efforts:

Specifically, the Problem areas identified in the previous phase are resolved during this phase by taking appropriate actions. The re-qualification reports demonstrate that the criteria of DAR Section 7.1.7 have been complied with.

Phase IV: Modifications to E ui ment or E ui ment Su orts:

Equipment or their Supports needing modifications identified during the regulations efforts of Phase III are executed during this phase.

The following are NSSS equipment:

SYSTEM MPL ij Safety Relief Valve B21F013 MSIV B21F022/F028 Flow Element B21N051/52/53/54 Recirc. Pump Motor B31C001 Gate Valve B31F023/31/32 HCU C12D001 CRD Valves C12F009/10/ll/12 SLC Storage Tank C41A001 SLC Accumulator C41A003 SLC Pump C41C001 SLC Explosive Valve C41F004 Rev. 22, 4/81 123.3-2

SSES-FSAR RHR Heat Exchanger E11B001 RHR Pump E11C002 Flow Orifice Assembly E11N012/N014 LPCS Pump 6 Motor E21C001 Flow Orifice Assembly E21N002 MSIV Heater E32B001 MSIV Blower E32C001/C002 HPCI Pump E41C001 HPCI Turbine E41C002 Flow Orifice Assembly E41N007 RCIC Pump E51C001 RCIC Turbine E51C002 Flow Orifice Assembly E51N001 Fuel Prep Machine E18E001 Gen. Purpose Grapple F18E011 Dryer S Separator Sling F19E008 Head Strong Back F19E009 Control Rod Grapple F20E002 Refueling Platform E21E003 In Vessel Rack F22E006 Def. Fuel Storage Cont. F22E009 Fuel Storage Vault F22E012 CONTROL ROOM PANELS Reactor Core Cooling BB H12-P601 Power Range Monitoring Cabinet H12-P608 RPS Div. 1 and 2 Log VB H12"P609 RPS Div. 2 and 3 Logical VB H12-P611 NSSS Temperature Recorder VB H12-P614 Feedwater 8 Recirculation Instrument Panel H12-P612 NSSS Process Instrument Panel H12-P613 Div 1 RHR/HPCI Relay VB H12-P617 Div 2 RHR/HPCI Relay VB H12-P618 ADS Ch A Relay VB H12-P628 MSIV Leakage Control Div 2 VB H12"P654 HPCI Relay VB H12-P620 RCIC Relay VB H12-P621 Inboard Valve Relay Board H12"P622 Outboard Valve Relay VB H12-P623 Div 1 CS Relay VB H12-P626 Div 2 CS Relay VB H12-P627 ADS Ch B Relay VB H12-P631 MSIV Leakage Control Div 1 VB H12-P655 Radiation Monitoring Instrument Panel A H12-P606 Radiation Monitoring Instrument Panel B H12"P633'12-P680 Operating BB Rev. 22, 4/8l 123.3-3

SSES-FSAR Termination Cabinets H12-P700 Series Plant Operation Benchboard H12-P853 NUCLEAR BOILER Condensing Chamber B21-D002 Condensing Chamber B21-D004AB Condensing Chamber B21-D006AD Condensing Chamber B21-D007AD Condensing Chamber B21"D008AD Condensing Chamber B21-D009AD LOCAL PANELS Reactor Water Clean-Up H23-P002 Reactor Vessel Ievel and Pressure (A) H23-P004 Reactor Vessel Level and Pressure (B) H23"P005 Recirculation Pump A H23-P009 Jet Pump B H23-P010 High Pressure Coolant Injection B H23-P014 Reactor Core Isolation Cooling A H23-Polj Residual Heat Removal Channel A H23-P018 Residual Heat Removal Div. 2 Channel B H23"P021 Recirculation Pumps H23-P022 Drywell Pressure Local Panel A H23"P057 Drywell Pressure Local Panel B H23-P058 Main Steam Isolation Valve Ieakage Control H23"P074 Div. 2 Core Spray Local Panel A H23-P001 Standby Liquid Control H23-P011 Main Steam Flow A/B H23-P015 High Pressure Coolant Injection Leak Det. H23-P016 Core Spray Channel B H23"P019 Main Steam Flow C/D H23-P025 High Pressure Coolant Injection H23-P036 Reactor Core Isolation Cooling Leak Det. H23-F038 Div. 2 (B)

Main Steam Flow A/B H23-P041 Main Steam Flow C/D H23-P042 Main Steam Isolation Valve Leakage Con. H23-P073 Div. 1 High Pressure Coolant Injection Div. 1 A H23"P034 Reactor Core Isolation Cooling Div. 2 B H23-P037 SRM/IRM H23-P030/31/32/33 NUCLEAR BOILER Temperature Element B21-N004 Temperature Element B21"N010AD Temperature Element B21-N014AD Rev. 22, 4/81 123.3-4

SSES-FSAR Pressure Switch B21"N015AD Temperature Element B21-N016AD Temperature Element B21-N017 Vacuum Switch B21-N056AD Temperature Element B21-N064 Differential Pressure Transmitter B31-N014CD Temperature Element B31-N023AB Differential Pressure Transmitter B31-N024AB Level Switch C12-N013AD I,evel Switch C12-N013EF Temperature Switch C41-N003 Pressure Transmitter C41-N004 Pressure Indicator C41"R003 Valve, Guide Tube C51-J004AE Miscellaneous Parts C51-5110001 Pressure Switch C72-N003AD Pressure Switch C72-N005AD Limit Switch C72-N006AD Limit Switch C72-N008AD I,evel Transmitter Ell-N008AB Temperature Element Ell-N009AD Differential Pressure Transmitter Ell"N013 Differential Pressure Transmitter Ell-N015A Differential Pressure Transmitter Ell-N015B Pressure Switch Ell-N018 Switch Ell-N021AB Pressure Switch Ell-N022AB Level Switch Ell-N023AB Level Switch Ell-N024 Temperature Element Ell-N029AD Temperature Element Ell-N030AD Flow Indicating Switch Ell"N033AB Differential Pressure Transmitter E21-N003AB Switch E21-N006AB Pressure Switch E21-N007AB Flow Meter E32-N006 Level Switch E41-N002 Level Switch E41-N003 Level Switch E14-N014 Ievel Switch E41-N015AB Ievel Switch E41"N018 Temperature Element E41-N024AB Temperature Element E41-N025AH Temperature Element E41-N028AB thru E41-N030AB Temperature Indicator E41-R002 I,evel Switch E51-N010 Temperature Element E51-N011AB Rev. 22, 4/81 123.3-5

SSES"FSAR Temperature Element E51-N021AB Temperature Element E51-N022AB Temperature Element E51-N023AB Temperature Element .

E51-N025AD thru E51-N027AD Temperature Indicator E51-R005 Temperature Element G33-N016AF Temperature Element G33-N022AF Temperature Element G33-N023AF Switch G33-N044A Rev. 22, 4/81 123.3-6

SSES"FSAR QUESTION 123.4:

Describe the methods and criteria used to determine the acceptability of the original equipment qualification to meet the required response spectra of item 2. (iii). - 123.2 (iii).

RESPONSE

I. BOP For cases. where the original spectra for which an equipment was qualified enveloped the combined Seismic and hydrodynamic load spectra of Item 123.2 (iii), the equipment is considered qualified. Otherwise (which is true for most cases) the equipment, is requalified for the combined spectra to meet the criteria discussed in response to Questions 123.1. These criteria are described in Section 7.1.7 of the Design Assessment Report.

II. NSSS The methods and criteria used to determine the acceptability of the original equipment qualification may be found in General Electric Company's Proprietary reports: NEDE-24788, "Seismic Qualification Review Team (SQRT) Technical Approach for Re-Evaluation of BWR 4/5 Equipment"; and NEDE-25250 "Generic Criteria For High-Frequency Cutoff of BWR Equipment".

Rev. 22, 4/81 123.4-1

SSES-FSAR Describe the methods and criteria used to address the vibration fatique cycle effects on the affected equipment due to required loading conditions.

RESPONSE

I. BOP As described in Subsection 3.7b.3.2 of FSAR, in general, the design of equipment is not fatigue controlled since the number of cycles in an earthquake is low.

For combined Seismic and hydrodynamic loads for equipment qualified by analysis, the fatigue effects are implicitly considered since the stresses due to SRV (which are generally controlling for fatigue) are a small contribution to the overall equipment stresses.

Fatigue effects in BOP equipment qualified by testing are accounted for by repetition of the tests. Typically tests are done for 5 OBE (or 5 upset conditions, i.e., OBE + SRV + LOCA) followed by 1 SSE (or 1 faulted condition, i.e., SSE + SRV + LOCA) in each of front-to-back/vertical and side-to-side/vertical biaxial configurations. In addition, on some selected pieces of equipment, vibratory table testing is carried out for an extended duration of time (such as 30 to 60 minutes) beyond the combined loading test. The input motions for the extended duration tests will be such that the generated test response spectra for any segment of the extended duration tests will envelope the SRV spectra. Furthermore, it will be ascertained that the equipment performs its intended function before, during and after the vibratory table tests. The results of the extended duration tests will be documented in the respective qualification reports.

II. NSSS Vibration fatigue cycle effects for NSSS equipment designed to ASME code requirements was reviewed at GE by NRC consultants from Battelle Pacific Northwest Laboratories on October 7, 1980. The consultants stated satisfaction with the GE approach which encompasses OBE, SRV, thermal and pressure cycles.

Non ASME Code components qualified by test address the "strong motion" phase of seismic and SRV dynamic motion sufficient to generate maximum equipment response. These loads are controlling. GE testing generally consists of 5 upset and 1 faulted test of 30 seconds each which is about 50$ greater than required to address strong motion vibration.

Rev. 22, 4/81 123.5-1

SSES-FSAR Non ASME Code components qualified by analysis generally have not, in the past, had to address vibration fatigue cycle effects. In most cases, such effects are not now part of the qualification record.

Rev. 22, 4/Sl 123.5-2

SSES-FSAR Based on the methods and criteria described in items 4 and 5, provide the results of the review of the original equipment qualification with identification of (1) equipment which has failed to meet the required response spectra and required requalification, and (2) equipment which was found acceptable, together with the necessary information to justify the adequacy of the original qualificatioa.

RESPONSE

I. BOP For cases where the original seismic reports can be extended to qualify an equipment for combined seismic and hydrodynamic loads by inspection and subsequent concurrence by vendor, such documents form a part of the qualification package. The following pieces of equipment bought under the indicated purchase order (P.O.) fall into this category:

(1) Cooling and chilled water pumps (P.O. gM-327)

(2) Expansion Tanks and Air Separator Taaks (P.O. AM-302)

(3) Nitrogen Gas Accumulators (P.O. j/M-156)

The rest of the BOP equipment is being qualified for the criteria described in Section 7.1.7 of the Design Assessment Report. The qualification reports for this equipment will provide the appropriate documentation.

II. NSSS Refer to the Response to Question 123.3 for the list of equipment reevaluated by GE oa the Susquehanna SQRT Program. All of the equipment listed in qualified to SQRT Criteria with the exception of the followiag:

B21"F022/F028 MSIV Data required from vendor B31-F031/F032 Gate Valve Operability deflection analysis required C12>>F009/F010 CRD Valve Operability deflection analysis F011/F012 required C41-A003 SLC Accumulator A/E pipe accelerations required C41-F004 SLC Explosive A/E pipe accelerations required Valve E32-B001 MSIV Heater Test required Rev. 22, 4/81 123.6-1

SSES-FSAR E41-C002 HPCI Turbine Test required E51-C002 RCIC Turbine Analysis of lube oil piping required F22-E006 Invessel Rack Analysis required F22-E009 Def. Fuel Storage Analysis required Cont.

H12-P608 Power Range Test required Monitoring Cabinet H23-P030 SRM/IRM Panels Test required "P031 "P032

-P033 163C1158 Flow Transmitter Test required on H23-P074 272A8005 Switch on H12- Test required P853 272A8006 Switch on H12- Test required 853 Information to justify qualification of the equipment selected by the NRC for the Site Audit will be available at the site for NRC inspection. Information to justify qualification of the remainder of the equipment is available for NRC audit at GE-San Jose.

Rev. 22, 4/Sl 123.6-2

SSES-FSAR Describe procedures and schedule for completion of each item identified in item 6.(1) 123.6 (1) that requires requalification.

RESPONSE

I. BOP Typically, the qualification program is executed in the following steps.

o Determine Qualification Awards Request Vendor (or Consultant) Quote Receive and Evaluate Quote Place Purchase Order o Perform Qualification REview Test Procedure Review Analysis Methodology Begin Analysis or Testing o Final Completion Receive and review Requalification Reports Final Approval of the Report The schedule for the completion of the qualification program is shown in the attached Table 123.7-1.

II. NSSS The response to Question 123.6 lists the equipment found by GE to require requalification along with a statement defining the work to be performed. All requalification will be completed on a schedule sufficient to permit NRC review prior to fuel load.

Rev. 22, 4/Sl 123.7-1

Page 1 of 6 TABLE 123.7-1 SCHEDULE FOR COMPLETION OF E UIPMENT REQUALIFICATION SQRT No. of Items/ Completion Form No. E~ni ment 2 Units Date E-109-1 4 kV Switchgear 12 3-13-81 E"109-2 4 kV Switchgear Sub-Components 12 5-15-81 E-112 ESW 8 RHR Pump Motors Complete E"117-1 480 V Safe-Guard Load Center Unit 3-27-81 Substations E-118 480 V Motor Control Centers 24 4-17-81 E"119A"1 Battery Monitors 20 3-27-81 E-119A-2 Battery Fuse Boxes 16 3-27-81 e

E-119A-3 Battery Chargers 22 3-27-81 E-119BC 24 Vdc, 125 Vdc S 250 Vdc 5-29"81 Battery Cells 6 Racks E-120-1 125 Vdc Distribution Panels 16 3-20-81

-120"2 24 Vdc Distribution Panels 4-10-81 E-121-1 125 V 6 250 Vdc Ioad Centers 12 3-27-81 E-121"2 250 Vdc Control Centers 4-10-81 E-135-1 Electrical Penetration 12 5-15-81 (Medium Voltage)

E-135-2 Electrical Penetration 32 5-15-81 (Low Voltage)

E-136 AC Instrument Transformers 14 3-27-81 E" 151 Motor Generator Sets 8 Control 4 Sets Complete Cabinet E-152 Automatic Transfer Switches Complete E-155 Control Switches 44 6-15-81 J-038A Field Mounted 32 Complete Electronic Pressure Transmitters Rev. 22, 4/81

Page 2 of 6 SQRT No. of Items/ Completion Form No. E~ni ment 2 Units Date J-03B-1 thru Panel Mounted Instruments 242 4th quarter 1981 J-03B-14 J-05A-14,31,33,37, Control Panels 6 Devices 31 5-30-81 (panels) 10A 6 B, 43,47,49, 6-15-81 (devices) 92,93,95 6 97 J-05B-1 Remote Shutdown Control Panel 5-30-81 (panels) 6-15-81 (devices)

J-27 Reactor Coolant Pressure Boundary Complete (panels)

Leak Detection System 6-15-81 (devices)

J-31 Annubar Flow Elements Complete J-59-1 thru RTD's 54 5"22-81 J-59-10 J-65-1 thru Control Valves in Nuclear Service 28 3-27-81 J-65-4 J-65B-1 thru Control Valves in Nuclear Service 86 3-27-81 J-65B-ll J-69-1 6 2 Pilot Solenoid Valves 5-15-81 J-69B-1 thru 6 Pilot Solenoid Valves 74 5-15-81 J-70-1 Pressure Regulating Valves 5-15-81 J-70-2 Process Solenoid Valves 76 5-15-81 J-92-1 thru Excess Flow Check Valves 238 5-1-81 J"92-5 J-98 Carrier Modulator 6"15-&1 (Isolator)

M-ll ESW Pumps Complete M"12 RHR Suction Water Pumps Complete M"22-1 6 2 Reactor Building Cranes 4-3-81 M-30 (78 forms) Diesel Generator 4 Sets Complete M-30 (6 forms) Diesel Generator 4 Sets 2"27-81 M-55 Reactor Vessel Top Head Insulation Complete Support Steel Rev. 22, 4/81

Page 3 of 6 SQRT No. of Items/ Completion Form No. E~ni ment 2 Units Date E -58 Diesel Oil Transfer Pumps Complete M-60 Buried Diesel Generator Fuel Oil 3-27-81 Storage Tanks M-87-1 Containment Hydrogen Recombiners 5-15-81 M-87-2 Hydrogen Recombiner Power Supply Complete M-90 Fuel Pool Skimmer Surge Tanks 4-27-81 M-149 Containment Vacuum Relief Valves 20 5-22-81 M"151 Suppression Pool Suction Strainers 32 Complete M-156 Containment Nitrogen Gas 60 Complete Accumulators M-159-1 thru Nuclear Safety 8 Relief Valves 58 5-1-81 M-159-21 M-160AC SRV Discharge Line 8, RHR Relief 68 5-15-81 Valve F055 Discharge Line Vacuum Breakers M-164 CRD Vent Valve Platform Complete

-192 High Density Spent Fuel Pool 48 Modules Complete Racks M"302 Expansion Tanks 6 Air Separators Complete M-307-1 thru Centrifugal Fans 3-13-81 M-307-3 M-308"1 Vane Axial Fans, Reactor Building 5-1"81 M-308"2 Vane Axial Fans, Diesel'enerator Complete Building M-308-3 6 4 Vane Axial Fans, ESSW Pumphouse Complete M-309-1 thru Air Handling Units 12 4-17-81 M>>309-4 M"310 Centrifugal Water Chillers 5-22-81 M"315 Reactor Building Unit Coolers 24 5-29-81 M-317 Drywell Unit Coolers 12 3"27-81

'-320"1 Chlorine Detectors 6-15-81 Rev. 22, 4/81

Page 4 of 6 SQRT No. of Items/ Completion Form No. ~Eni ment 2 Units Date M-320-2-1A 6 1B Flow Switches 28 6-15-81 M-320-2-2A Flow Switches 6-15-81 M-320-3 Level Gauge 6-15-81 M-320-4 Pressure Differential Switches 6-15-81 M-370-5A 6 5B Temperature Switches 24 6-15-81 M-320-6-1A 6 1B Temperature Switches 6-15-81 M"320-6-2A Temperature Switches 6-15-81 M-320"6-3A 6 7 Temperature Switches 10 6-15-81 M-320-8 Pressure Differential Transmitter 18 6"15-81 M-320-9 Temperature Detector Unit 6-15"81 M-320-10 Level Switches 4 6-15-81 M-321"1 Standby Gas Treatment System- 2-20-81 Housing M-321-2 Standby Gas Treatment System- 5-1-81 Deluge Drain Valves M"321-3 Standby Gas Treatment System 3-6-81 Control Panels M"323C-1 Air Flow Monitoring Unit 3"13-81 M-323C-2 SGTS Exhaust Vent Flow Condition- 3-13-81 ing 8 Sampling Probe System M-325 High Efficiency Ventilation Filters Complete M-327-1 Chilled Water Pump Complete M"327-2 Cooling Water Pump Complete M-334-1 thru HVAC Control Panels 6 Devices 12 5-30-81 (panels)

Z-334-5 6-15-81 (devices)

M-336A HVAC Dampers 195 Units 5-8-81 M-362 SGTS Centrifugal Fans Complete M"365 Chilled Water Relief Valves 5-1-81 P"10A-1 Motor Operated Gate Valves, 6008 6-15-81 Rev. 22, 4/81

Page 5 of 6 SQRT No. of Items/ Completion Form No. E~ni ment 2 Units Date

-10A"2 Motor Operated Gate Valves, 9008 15 6-15-81 P-10A-3 Motor Operated Globe Valves, 9008 6-15-81 8 6008 P-10B Motor Operated Stop Check Valves, 6-15-81 9008 P-11A-1 Motor Operated Gate Valves, 6-15-81 900'ir P-11A-2 Operated Testable Check Valves, 6"1-81 9008 P"12A-1 Motor Operated Gate Valves, 150j/ 24 6-15-81 P12A-2 Motor Operated Globe Valves, 300j/ 6-15-81 P12A-3 Motor Operated Gate Valves, 300j/ 20 6-15-81 P-12A"4 Gear Operated Gate 8 Globe Valves, 6-1-81 300 jj P-12B-1 Motor Operated Gate 6-15"81 Valves, 150jj 6 3008 P-12B"2 Air Operated Gate Valves, 150j/ 14 6-1-81

-12B"3 Gear Operated Gate 8 Globe Valves, 13 6-1-81 150 jj P-14A Motor Operated Globe Valves, 15008 6-15"81 P-14B Motor Operated Globe Valves, 1500// 6-15-81 P-15A Motor Operated Globe Valves, 15008 6-15-81 P15B-1 Motor Operated Gate Valves, 15008 18 6-15-81 P-15B-2 Air Operated Gate Valves, 6-1-81 1500'otor P-16A-1 Operated Butterfly Valves, 28 6-15-81 150 jj P16A-2 Air Operated Butterfly Valves, 6-1-81 1500 P-16A-3 Gear Operated Butterfly Valves, 12 6-1-81 150 jj P"17A-1 Motor Operated Gate Valves, 900j/ 6-15-81

-17A-2 Motor Operated Globe Valves, 9008 6"15-81 Rev. 22, 4/81

Page 6 of 6 SQRT No. of items/ Completion Form No. E~ni ment 2 Units Date P-17A-3 Air Operated Testable Check 6-1"81 Valves, 9008 P"17A"4 Gear Operated Gate Valves, 900// 6-1-81 P-17B Air Operated Testable Check 6-1-81 Valves, 90017 P-18A Gear Operated Gate Valves, 1508 6-1-81 P-31A Air Operated Butterfly Valves, 6-1-81 1508 Rev. 22, 4/81

SSES-FSAR UESTION 123.8 Describe plans for a confirmatory in-situ impedance test and an in-plant SRV test program or other alternatives to characterize the ability of equipment to accommodate hydrodynamic loading.

RESPONSE

In-Situ tests are being performed for the determination of structural dynamic characteristics of the equipment for in-service condition. This in-situ information is being used as supporting evidence for (a) validating a mathematical model for qualification by analysis, or (b) simulating the in-service condition on the vibratory table tests for qualification by testing. The results and the usage of in-situ testing will be described in the respective qualification reports, whenever such tests are performed.

All safety related BOP equipment fo Susquehanna project is being qualified for combined seismic and hydrodynamic loads for the criteria described in Section 7.1.7 of DAR. Susquehanna has no plans to perform an in-plant SRV test for equipment qualifications,per se. An air bubble test was conducted in the suppression pool in an attempt to simulate the effects of an SRV air clearing transient load. The data from this test are being studied in an effort to determine the extent of conservatisms in the analytical prediction of applied hydrodynamic loads.

Rev. 22, 4/81 123.8-1

SSES-FSAR To confirm the extent to which the safety related equipment meets the requirements of General Design Criterion 2, the Seismic Qualification Review Team (SQRT) will conduct a plant site review. For selected equipment, SQRT will review the combined required response spectra (RRS) or the combined dynamic response, examine the equipment configuration and mounting, and then determine whether the test or analysis which has been conducted demonstrates compliance with the RRS if the equipment was qualified by test, or the acceptable analytical criteria analysis.

if qualified by The staff requires that a "Qualification Summary of Equipment" as shown on the attached pages be prepared for each selected piece of equipment and submitted to the staff two weeks prior to the plant site visit. The applicant should make available at the plant site for SQRT review all the pertinent documents and reports of the qualification for the selected equipment. After the visit, the applicant should be prepared to submit certain selected documents and reports for further staff review.

RESPONSE

Susquehanna SQRT pre-visit information required for the SQRT site review has been submitted for all BOP and NSSS equipment. "Qualification Summary of Equipment" and the pertinent documents, reports, vendor prints and all necessary information as required are available for SQRT review.

Rev. 22, 4/81 123.9-1

SSES-FSAR The Susquehanna FSAR Section 3.7b.2.1 indicates that both a flexible base model and a fixed base model were utilized for the seismic analysis of the containment building. Discuss and explain the rationale for using two different models for the seismic analysis.

Demonstrate the equivalency of the two models by comparing their dynamic characteristics on the results from the two analyses.

RESPONSE

A fixed base model can be justified since the containment is founded on hard, competent rock. The minimum shear wave velocity, Vs, for the rock is 6200 fps (reference: Subsection 2.5.4.2.1). Therefore, structural design of the containment was based on the fixed base results.

A flexible base analysis, which takes into account soil structure interaction effects, was used to generate structural response spectra for evaluation of equipment, piping systems, etc. See attached Figures 130.20-15 through 130.20-18 for comparative response spectra at the top of the reactor pedestal for both fixed and flexible base results.

The structural accelerations, shear forces, bending moments and axial forces for the fixed and flexible base analyses generally differ by less than 20% with the majority of values within 10-15'his is shown in the attached Figures 130.20-1 through 130.20-10. Therefore, the two results are considered comparable. Since seismic forces for the Susquehanna site account for less than 20% of the total maximum reinforcing steel stress for the governing load combination, the 20% maximum increase in seismic response for the flexible base results would result in only a 4% increase in stress. This increase in stress is well within the existing design margin.

The flexible base displacements are larger than the fixed base displacements by approximately 20-50%. This is shown in the attached Figures 130.20-11 through 130.20-14. These larger displacements for the flexible base analysis were used to determine the required separation between the containment and the surrounding reactor and control buildings.

Rev. 22, 4/81 130.20-1

SSES-FSAR In Torsional Analysis of Diesel Generator Building and ESSN pumphouse:

Justify the use of static analysis for a dynamic phenomenon.

RESPONSE

Subsection 3.7b.2.11 states "A static analysis was done to account for torsion...". This statement pertains to the distribution of seismic forces.

During the dynamic analysis stage the inertia force at each mass. However, since the center of rigidity does not coincide with the center of mass, there is torsion. The inertia force obtained from the dynamic analysis was used by multiplying it with the eccentricity (the distance between the center of mass and the center of rigidity) to obtain the torsional moment. This moment was then distributed to the structural walls for assessment.

A minimum excentricity of 5% was considered.

Rev. 22 4/81 130.21-1

.136 Flexible Base Model Results

~ 0.128- Fixed Base Model Results,

~228

~8'83 I 22 0.614

, 0.220

~ca (. ZS8 I o.2oo 0.240 .~sos

~

3 0.446 I

/9'5' 23 I

I I

I 0.175 j~345' I 24 0.294 I 15 I

I ./8/ ~/9 7 0.154 I

I j~2/ g 0.183 i~/so ~/8 I 0.137 I '~/36 l~/2 o.128 '7 0.128 I ./

j~/0 8 ~/2 0.109 18 0.108 I.oeq UNITS: G's I

I j~ot3 10 0.091 26

~os'u I

~>77/ ~078 11 19 0.071 I

I 12 I,0.046 052 I.o~tf I

I Rev. 22, 4//81 I

.032 ~

a SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 13 0.021 21 0,020 FINAL SAFETY ANALYSIS REPORT CONTAINMENT HORIZONTAL ACCELERATIONS OBE FIGURE 130. 20-1

~//Z7 22 0,751 I

'~Z'M

.39 l 14 0.331 ~55 4 0.545 0.251 23 I, I

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, 0.215 (~441 24 0.360 I

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~/5 t . (z+

0.161 7 0.152 ' 17 0.161

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(~/48 57 8 0.137

~

18 0.140 UNITS: G's l~/36 9 l 0.126 I I

~/32 10 0.121 26 I

~/z5 I

i~/o3 ~/2o 0.092 19 0.100 I

I jlloBo( ~iot 12 , 0.067 20 0.073 I Rev. 22, 4/81 l

I

~o52 ,d5 SUSQUEHANNA STEAM ELECTRIC STATION 13 0.034 21 0.034 UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CONTAINMENT HORIZONTAL ACCELERATIONS SSE

. 136 Flexible Base Model Results F IGIIHE. 130. 20-2 0.128 - Fixed Base Model Results .

.040 0.059

. /03 I

22 0.103

~040 l

> O.OS9 I

l

~03'P ~ocr I~ioo

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15 ~

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UNITS: G's 0.032 I ~ C j~o4o 10 n 0.035 I l

~

27 28 29 26 I

.uz0 ~o 0.024 I 19 0.026 l I I

~020 ~os I l~o2 12 0,015 3p 0.012 2p 0.017 I

I f l.

l~Oia I j~o>

Rev. 22, 4/81 I

13 21 fo.oov O.OI77 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CONTAINMENT o.136 Flexible 0.128 Fixed Base Model Base'odel Results Results F IGIJ VERTICAL,ACCELERATIONS RE 130. 20-3 OBE l

~ ops 0.1 12

'~is 5 I

22 0.162

~O7 O I 0.111 I

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15 0.096 f

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0. 131

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~ os 8 'Idio 0.082 17 0.085 0.085

~os@ ~oII8 0.073 0.070

.062 9 I

~ 050 0.059 ~ 057 0.045 0.046

. 005 0& /~07 10 0.055 t UNITS: Q'g 427 28 4 29 26 I

I

,CoOg ~os q 0.050 19 0.04 1 I I

~osv ~os ~ ~os 12 0.029 30 0.022 20 0.027 I

4 I I I

~oso I i~&i 13 0.01 2 21 0.01 1 Rev. 22, 4/81 I I SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS'EPORT CONTAINMENT I

VERTICAL ACCELERATIONS 136 .Flexible Base Mode'1 Results

~

%RE 0.3.28 Fixed Base Model Results

~

~

FIQURE ~ 130. 20-4

46 ~44 256 2g 31 164 ~(97 102 ~104 260IM2~'

14 23

~

1,>>0 l300 423 gag 288 3t5 24 15 1,440 I&20

~IRIDO eee ~e'735 264 ~$ 1 g 25 7,770 16 766 f99$ 4 24e~ek1$~

2,070 ~2'LQO 17 17 2,220 ~14)0 646~59 18 2,550 Q tI0

~ 589 70'7 2,720 ZERO 10 26 3,620 4000 ss1 ~>ag UNITS: KIPS

>> 19 3,830 'tZI0 364 558 12 20 4.010 ~44 l 0 4O2 ~WOa 13 21 4,1 00~$ 55 Q 424 $ 35 27 27 Rev. 22, 4/Sl SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CONTAINMENT SHEAR FORCES D

.136 Flexible Base Mo'del Results 0.128 Fixed Base Model Results FIGURE OBE 130.20"5

se ~4e 010 ~573 201 ~255 31 366 48 I 126 1+0 14 23 1,380 I6 $ 0 010~654 ese ~4I l4 24 15 1.7so ~2l 3 0 ceo ~8q g 440 ~41 93 ~Italo 25 2,180 Z 55 0 16 014 404 f449 e,sso ~Z4l 50 17 17 2850 3ggg 011~85 l 18 3.110 [335l 0

.720 9 I 2.

e,eeo ~380 10 26

'430 SZSQ 404 444 UNITS: KIPS 19 4,68o 5590 447 ~485 12 20 4,91o 5300 4ee ~549 13 21 0,040~kola see ~6O7

'7 27 Rev. 22, 4/81 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 II FINAL SAFETY ANALYSIS REPORT CONTAINMENT

..136 - Flexible Base Model Results SHEAR FORCES 0.128 Fixed Base Model Results ARE FIGURE 130.20-6

1 0 22 0 2 0.50 ~O. QS 2 4,22 ~W.S/ 14 0 22 2.ss ~Z.pg 4 216 2 '5 ~

24 2.42 P . ag 15 8.33 F. '7 4 5 4o.s ~6.0 25 16.8 ~III.Z 61,0 ~6l 0 ~

16 15.4 ~IS ~ /

17 183 2I 3 17 28.8 ~3'7. I 81.2 ~f/ 0 ~

108 //.

105 ~ll 5 18 173 ZD, 2 124 ~/'37 10 145 I ~l 26 24.8 Z V. 5 149 tgy 196 23,2 UNITS: 10'.F T so1 ~2.22 19 16.6 ~242. 62 12 256 m3 20 14.9 l 7. 8 13 214 ~34lo 21 15.s ~l7. 5 27 18.0 /'7. I Rev. 22, 4/81 27 222 ~@/ 2 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT

' CONTAINMENT MOMENTS 0

0

.136 Flexible Base Model Results.

'28 Fixed Base Model Results.

FIGURE OBE 130. 20-7

1' 22 0 2 0.63 0. 7 /o s s.ss ~6. 3& 14 0 23 2.87 3, 2 Co

4. 2s.g ~3z. s 24 9.14

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10. 178 208 26 SOS 38 2 183 QJ g 24.0 304 ] UNITS: 10s K-FT 24s ~ZOO ~

19 so.s ~Z5. 5 12 sis ~37 20 is.s ~z3. o 13 sss ~453 21 12.7 ~Z'Z. 7 27 4~~53S 22 220 qg,+ Rev. 22, 4/81 SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT.

CONTAINMENT MOMENTS 136 Flexible Base Model Results

~

s'c'C 0.128 Fixed Base Model Results

~ FIGURE 130.20-8

2'2 sv ~4&

14 23 ieo ~~f2 I 131 J rO 15 24 ees

~IZED>

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491 503 10 -26 7'Z 7 920 396 Q'26 UNITS: KIPS 1,010 <>s

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I

>>~+'2 126 Jg 6

67 77 23 256 ~240 26 r5 2os

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~lS I 't 1720 614 ~76 0 1900 642 ~7i 'l l 12 2010 f12'0 662 126 ~3544' Rev. 22, 4/81.

13 l. 21

~t70 SUSQUEHANNA STEAM ELECTRIC STATION 2050 669 UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT D5 CONTAlNMENT AX(AL FORCES 136 Flexible Base Model Results SSE

~

0.128'

~ Fixed Base Model Results

~

FIGURE '30..20-10

136 - Flexible

~

Base Model Results

0. 128 Fixed Base Model Results

~

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jCn3 UNITS: 10 FT 10 1 1.7 26 l I tc,C.

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I~~,S I 12 '.69 20 3.54 I

Rev. 22, 4/81 I

~4'.oe SUSQUEHANNA STEAM ELECTRIC STATION 13 1.89 21 '.10 UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CONTAINMENT

't. t8 HOB I ZONTAL D I SP LACENIENTS OBE FIGURE 130. 20-1 1

D 136 0.128

- Flexible Base Model Results Fixed Base Model Results S 5 38.6 I

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Rev. 22, 4/8i I~a,ss 3.'t SUSQUEHANNA STEAM ELECTRIC STATION 13 2.32 21 i 1.37 UNITS 1 AND 2 SAFETY ANALYSIS REPORT,

'INAL CONTAINMENT

~<.sv HORIZONTAL DISPLACEMENTS SSE FIGURE 130.20-12

~o.f 98 0.812

~Z.W 7 I

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'2 I

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. 34 10 27 28 '9 I

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0.667 I I I l~u~z I aazs 12 30 0.215 20 0.427 I I I~a.slh I g,+70 13 0.090 21 0.181 Rev. 22, 4/81

~d,Z95 '~0,%9S ~AZ'FS SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT

.$ 36 - Flexible Base Model Results CONTAINMENT VERTICA'L D ISP LACEMENTS 0.128 Fixed Base Model Results OBE P I G I I R E, 130. 20-13

1.53 I 5-5 1 22 4.18 1.51 I I I

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0.775 0.754 e

! ~i~

1.39 UNITS: 10 4FT 27 28 29 26 f I

~o< j j~l. 74 0.616 ~ 19 i 1.04 I I I~O,RSL . ~I.'L'9 12 30 0.364 20 0.663 I I j

j~o.aa j~o.ass 13 0.170 21 0.282 Rev. 22, 4/81 I I I

~5Kb 5,'5%> O.S3o SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 FINAL SAFETY ANALYSIS REPORT CONTAINMENT

.136 Flexible Base Model Results VERTICAL DISPLACEMENTS SSE 0.128 Fixed Base Model Results FIGURE . 130.20-14

1.800 1.600 1.400 zO 1.200 Pk~'hie Wse cc 1.000

.800

..600

.400

.200

.000 0.1 '0.2 0.4 0.6 1.0 2.0 4.0 6.0 10.. 20. 40. 60. 100.

FREQUENCY (HZ)

LOCATION: RPV PEDESTAL DIRECTION: HORIZONTAL EARTHQUAKE: OBE DAMPING: 0.005 Rev. 22, 4/Sl SUSQUEHANNA STEAM ELECTRIC STATION UNITS 1 AND 2 I. FINAL SAFETY ANALYSIS REPORT RESPONSE SPECTRUM AT'RPV PEDESTAL HORIZONTAL OBE FIGURE 130. 20-15

0

/ 3.000 2.700 2.400 2.100 F(exltl i.soo bd$ 8 z0 I-a 1.500 1.200 900 600

~ 300

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FREQUENCY (HZ)

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FREQUENCY (HZ)

Rev. 22, 4/B1 SUSQUEHANNA STEAM ELECTRIC STATION

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,7.

SSES-FSAR QUESTION 130.22:

r Explain why the analysis for the torsional effect was not done for the Reactor Building.

RESPONSE':

The torsional effect in the reactor/control building was considered in the dynamic analysis. Units 1 and 2 were considered simultaneously.

In the N-S direction the eccentricity is larger than 5%. The N-S dynamic model presented on Figure 3.7b-10 of FSAR consists of 3 sticks at each floor and the stiffness distribution of the structural walls are such that proper representation of the eccentricity is obtained. Therefore, the torsional effect is properly accounted for in the dynamic analysis. The computed dynamic member forces and model paint responses were used for the assesment of structure and equipment.

In the E-W direction (see seismic model on Figure 3.7b-9) the eccentricity is less than 5%. However, a miriimum eccentricity of 5% was considered by redistributing the masses. This was done for the assesment of walls.

Rev. 22 4/81 130.22-1

SSES-FSAR In Figure 7-6 which shows downcomer bracing system details, it appears that the bracing is welded to the liner plate through the use of an embedded plate without any anchorage to the containment concrete wall. Since the steel liner plate is not a structural component, indicate how the pulling forces from the bracing can be resisted and how the leaktight integrity of the liner can be maintained.

RESPONSE

Downcomer bracing forces are resisted by embedded anchorages in the containment concrete wall. This design assures the leaktight integrity of the liner plate is maintained.

Rev. 22, 4/81 130.23-1

SSES-FSAR It appears that portions of the recirculation pump seal cooling water are not seismic Category I (Regulatory Guide 1.29). The staff requires additional information to show that a complete loss of pump seal cooling water would not lead to unacceptable consequences.

RESPONSE

Two non seismic Category 1 sources of cooling are available to the recirculation pump seals: recirculation pump seal cooling water supplied by RBCLCW and recirculation pump seal injection water supplied by the CRD -system.

General Electric's Licensing Topical Report, NED0-24083, Recirculation Pump Shaft Seal Leakage Analysis, provides : an analytical basis for recirculation pump seal leakage, assuming a failure of both cooling water systems. This generic analysis predicts a bounding leakage rate well under 100 gpm. The generic analysis is applicable to Susquehanna. The report also documents test results, demonstrating that pump seal integrity will be maintained if any one of the two cooling water systems is out of operation at a given time.

Rev. 22, 4/81 211.1-1

SS ES-FSAR QUESTION 211. 8 The SRP 5 4.7 states the residual heat removal system (RHRS) should meet the requirements of General Design Criterion (GDC) 34 of Appendix A to 10 CFR Part 50. The RHR by itself cannot accomplish th cheat removal functions as required by GDC 34. To comply with the single failure criterion the FSAR describes an alternate method of achieving cold shutdown in Section 15.2.9 Insufficient information is provided to allow an adequate evaluation of this alternate method. In particular, we have recently approved Revision 2 to SRP 5.4.7 (containinq Branch Technical Position RSB 5-1) which delineates accceptable methods for meeting the single failure criterion. This Branch Technical Position requires testinq to demonstrate the expected performance of the alternate method for achievinq cold shutdown. You should describe plans to meet this requirement. In addition, we require that all components of the alternate system be safety grade (seismic Cateqory I) .

As a result of this requirement, the air supply to the automatic depressurization system (ADS) valves, including the system upstream of the accumulators, must be safety grade. This air supply must be sufficient to account for air consumption necessary for valve operation plus air loss due to system leakage over a prolonged period with loss of offsite power.

RESPONSE.

As discussed in Subsection 9 3.1.5.1, the gas supply to the ADS values and the backup qas supply to the ADS accumulators is safety grade. Codes covering the design and construction of these compon'eats are discussed in Subsection 9.3.1.5.1 All components that are a part of the alternate shutdown loop (see Sd>section 15.2.9 & Figs.15.2-14 and 15,2-15 are routinely tested as required by technical specifications. Testing of the total alternate shutdown system would not provide any additional pertinent information and would result in introducing lower quality (suppression pool) water into the vessel. Bsed on the above, we do not feel that testing of the total loop is necessary or desirable.

This issue was tentatively resolved with the NRC on the Shoreham docket (BWR/4) by an agreement to test one safety relief valve in San Jose simulating the alternate shutdown condition. The rationale for acceptance of this plan was that the SRV is the only component in the loop which has not been demonstrated to be suitable for alternate shutdown conditions. This test. was successfully completed in December 1979.

Rev, 22 4/81 211 8-1

SS ES-PSAR General Hlectric in conjunction vith the Three Mile Island Owners Group is planninq further SRV testinq in response to TMI related issues. This testinq. vill include conditions similar to the alternate shutdovn- conditions and will include a valve of Crosby Manufacture as is used in the Susquehanna plant. It is expected that these tests will further confirm that an in-plant test is not required to demonstrate alternate shutdown conditions capability.

REV 18, 1 $/80 211 8- 2

SSES-I'SAR QUESTION 21 1 85:

Provide assurance that adequate NPSH exists for an ECCS passive failure in a water- tight pump coom. Address the possibility of vortex fo mation at the suction of the remaining ECCS pumps with the lowered pool level. Discuss preoperational tests to be performed to demonstrate that there is not impairment of ECCS function due to lowered suppression pool level.

RESPONSE

See Subsection 6.3.6 for discussion of NPSH availability with ECCS passive failure and of vortex formation in the suppression pool.

Testing for pump operation at minimum NPSH margin is provided by preoperational tests.

Rev. 22, 4/81 211 85-1

SSES-FSAR It is not evident that the assumed drop of 100 0 F in feedwater temperature gives a conservative result of this transient with manual recirculation flow control. For example, a feedwater temperature drop of about 150 F occurred at one domestic BWR resulting from a single electrical component failure. The electrical equipment malfunction (circuit break-trip of a motor control center) caused a complete loss of all feedwater heating due to total loss of extraction steam. Accordingly, either (1) submit a suf-ficiently detailed failure modes and effects analysis (FMEA) to demonstrate the adequacy of a 100 F feedwater temperature reduction relative to single electrical malfunctions or (2) submit calculations using a limiting FW temperature drop which clearly bounds current operating experience.

Also, temperature drops of less than 100 F can occur and involve more realistic slow changes with time. Assuming all combinations result in slow transients with the surface heat flux in equilibrium with the neutron flux at the occurrence of scram, a smaller temperature drop than 100 F that still causes scram could result in a larger QCPR. Please evaluate this transient and justify that the assumed values of the magnitude and time rate of change in the feedwater temoerature are conservative.

RESPONSE

No single electrical component failure will cause the loss of more than one train of feedwater heaters as separate power sources are supplied to each of the feedwater control panels. Each feedwater heater train consists of five feedwater heaters plus a drain cooler. SSES does not have a feedwater heater train bypass line.

The GE feedwater heater system design specification requires that the maximum temperature decrease which can be caused by bypassing feedwater heater(s) by a simple valve operation will be less than or equal to 100oF. This is the basis of the assumed drop of 100 F in feedwater temperature in the analysis.

Loss of one feedwater heater train at SSES will actually result in significantly less than a 100 F temperature drop.

It should be pointed out that a steady state (i.e., the surface heat flux in equilibrium with the neutron flux) is assumed in determining the MCPR during the transient. Therefore, a temperature loss smaller than 100 F is not expected to result in amy more severe a transient than that analyzed Rev. 22, 4/81 211.116-1

SSES-FSAR QUESTION 211.120:

For the recirculation pump seizure accident we note in Table 15.3-3 that credit is taken for nonsafety-grade equipment to terminate this event.

Section 15.3.3 of the Standard Review Plan, Revision 1, rewuires use of only safety-grade equipment and the safety functions be accomplished assuming the worst single failure of an active component. Reevaluate this accidentwith the above specific criteria, and provide the resulting CPR and percentage of fuel rods in boiling transition.

RESPONSE

The recirculation pump seizure enent, assuming the operation of specific non-safety grade equipment, has a mild impact in relation to the design-basis double-ended recirculation ling break in Sectouns 6.3 and 15.6.

Failure of such equipment would not make the core performance and/or radiological consequences of this highly improbable pump seizure (rapid core flow decrease) event more limiting than the maximum DBA-LOCA addressed in the FSAR. Therefore, no additional evaluations are considered necessary.

The FSAR text has been revised regarding frequency classification by deleting references to infrequent incident classification in Subsection 15.3.3.1.2 and 15.3 '.1.2, recirculation pump seizure and recirculation pump shaft break respectively Rev. 22, 4/81 211.120-1

SSES-FSAR Operation of Susquehanna with partial feedwater heating might occur during maintenance or as a result of a decision to operate with lower feedwater temperature near end of cycle. Justify that this mode of operation will not result in (1) greater maximum reactor vessel pressures than those obtained with the assumption used in Section 5.2.2, or (2) a more limiting 5MCPR than would be obtained with the assumptions used in Section 15.0. The basis for the maximum reduction in feedwater heating considered in the response should be provided (e.g., specific turbine operational limitations).

RESPONSE

Lower feedwater temperature increases the core inlet subcooling and results in a corresponding decrease in both the core average void fraction and the steam production. The feedwater temperature of 250oF is considered as the lower limit based on the conclusion that plants with improved interference fit spargers can be run in this mode (250 F FFVZ) without adverse consequences. Typically, the core average void fraction is reduced by -16$ when the feedwater temperature is reduced from 420 F to 250 F. The lower steam production rate reduces the peak pressures which occur during a transient (Table 211.125).

The use of feedwater temperature reduction to extend the cycle beyond normal EOC is not expected to result in more severe transients. The lower void fraction ( "16$ lower at 250 F FFWT) reduces the dynamic void coefficient and the severity of the transient (i.e., the ACPR due to the transient) is less. Table 211.125 provides the typical ACPR numbers for two transients analyzed. Although the scram reactivity response is somewhat degraded due to the less bottom peaked power shape, the overall response is dominated by the void feedback effects and the resulting transient is less severe. Reducing the feedwater temperature before EOC will not result in more severe plant transient either. The peak pressures will be less due to the reduced steam production. The ACPR will be less due to the smaller void coefficient. Due to the presence of a significant number of control rods inserted into the core for this condition, the scram response is not appreciably affected by the feedwater temperature reduction. In addition, the transient response at points in the cycle other than EOC is consistently less than EOC.

If operation in the reduced feedwater temperature mode is utilized, prior to operation an analyses will be performed to show this mode of operation will not violate MCPR safety limits, given the events in Chapter 15.

Rev. 22, 4/81 211.125-1

TABLE 211. 125 TRANSIENT ANALYSIS RESULTS Peak Reactor Exposure Vessel

~Cele Transient Point Pressure CPR BWR4 Load rejection Rated EOC 1235 .17 251"764 w/o bypass (104.2/ power)

Evil.

cycle (Reduced Feedwater) Extended EOC 1219 0.16 Heating (100$ power)

Feedwater Rated EOC 1202 0.12 Controller (104.2$ power) failure (Reduced'eedwater) Extended EOC 1060 0.05 Heating (100$ power)

• ODYN ANALYSIS RESULTS Rev. 22, 4/81

SSES-FSAR In the evaluation of the "generator load rejection" transient, a full-stroke closure time of 0.15 seconds is assumed for the turbine control valves (TCV). Section 15.2.2.3.4 states that the assumed closure time is conservative compared to an actual closure time of more like 0.20 seconds. However, in Figure 10.2-2, Turbine Control Valve Fast Closure Characteristic, an acceptable TCV closure time of 0.08 seconds is implied. Explain this apparent non-conservative discrepancy and the effect on analyses in Chapter 15 requiring TCV closure.

it has

RESPONSE

The 0.08 seconds shown in Figure 10.2.2 is an acceptable value whereas the .07 seconds TCV closure time in Tables 15.2-1 and 15.2-2 is the bounding value.

See response to Question 211.117 for further clarification to this question.

Rev. 22, 4/81 211.161-1

SSES-FSAR The narrative on page 15.4-13 discussing the "abnormal startup of an idle recirculation pump" transient states, "The water level does not reach either the high or low level set points." Table 15.4.3. indicates a low level trip occurs 22.0 seconds after pump start. Figure 15.4-6 indicates a low level trip occurs approximately 23.5 seconds after pump start. Further:

a) Table 15.4-6 indicates a low level alarm 10.5 seconds after pump start while Figure 15.4-6 indicates this alarm occurs about 11.5 seconds after the pump starts.

b) Table 15.4-6 indicates vessel level beginning to stabilize 50 '

seconds after the pump starts. Figure 15.4-6 shows no such indication.

Resolve these discrepancies.

RESPONSE

The sequence in Table 15.4-3 starts out with a scram at 10 seconds following the improper pump start. Figure 15.4-6 confirms this. At 23.5 seconds (rather than 22) level falls to L3 which also issues a redundant scram signal to a system which has already scrammed. It is the intent of Table 15.4-3 has been modified.

a) Table 15.4-4 indicates L4 near ll seconds. This is verified by Figure 15.4-6, b) Table 15.4-4 indicates that vessel level is beginning to stabilize at 50 seconds. This appears to be correct. Actually, level recovered from L3 at about 41 seconds and from 30 to 40 seconds level is changing at the rate of 2.5 in/sec. From 50 to 60 seconds level rate is definitely flattening out under normal feedwater level control.

Rev. 22 4/81 211.180-1

SSES-FSAR QUESTION 211.210:

Expand the discussion in Section 6.3 to describe the design provisions that are incorporated to facilitate maintenance (includinq draininq and flushing) and continuous operation of the ECCS pumps, seals, valves, heat exchangers, and piping runs in the long-term LOCA mode of operation considering that the water being recirculated is potentially very radioactive.

RESPONSE

The Susquehanna eguipment for long-term coolinq fcllowing a postulated LOCA includes two ccmplete coze spray systems and two RHR systems. These tvo systems consist of a total of eight pumps capable of pzovidinq water to the reactor pressure vessel. The pipinq and instrumentation diagrams of these systems are shown in Figures 6.3-4 and 5.4-13. Lonq-term cooling vater can be provided to the core by one RHR (LPCX mode) pump or one CS loop (both pumps), while heat can be rejected to the ultimate heat sink via either of the two RHR heat exchangers using one of four RHR pumps. Thus a maximum of three pumps vould be required for post-LOCA core coolinq. All of these components are desiqned to remain operable during and follovinq a Loss of Coolant Accident, and the redundancy provided is such that maintenance is not expected to be required during the long-tera core cooling period followinq a LOCA. Hovever, the RHR and Core Spray systems are designed with provisions for flushing as shovn in Figures 6.3-4 a nd 5. 4-13.

Rev. 22 4/81 211 210-1

SSES-FSAR gDESTXON 211.211:

Severe water hammer occurrence in the ECCS discharge piping during startup of the ECCS pumps is avoided by ensuring that the discharge pipes are maintained full of water. The condensate transfer system i used to achieve this function for all ECCS piping. Since the condensate transfer system also supplies ~ater to numerous other systems, the following areas require clarification:

a) Justify the use of a common filling system for all ECCS discharge piping versus ind,ependeni jockey pumps.

b) Identify the expected demands on the condensate transfer system and what effects, if any, would be expected on the makeup required to keep the discharge pipes full of water?

c) Can individual maintenance "fill lines" be on one ECCS system isolated to permit without affecting the other system?

d) The to discharge piping be an "fill system" is apparently considered auxiliary system. Are any priority interlocks provided to ensure that the "filling system" will be given priority over the other uses of the condensate transfer system water?

e) The individual fill lines apparently do not have instrumentation to monitor low pressure. provide assurance that when the condensate transfer pumps are operating that the individual ECCS discharge lines are full of water.

f) What is the history of water hammer events at other plants employing this design?

RESPONSE

a) The pump fill system adopted for Susquehanna SES utilizes the existing condensate system and is relatively simple. Zt is believed to have a higher system overall reliability than a system requiring individual pumps, or so-called jockey pumps, to perform the fill function. However, there is no known operating experience with a common discharge line fill system.

The condensate transfer system has been designed to be reliable insomuch as Therefore complete it is required for plant operation.

failure of this common filling system for the ECCS would require that the plant be brought to a shutdown condition.

b) At standby pressures substantially below valve rated pressures, the 'estimated makeup for the ECCS systems is less than l (one) gpm. See revised Subsection 6. 3. 2. 2. 5.

Rev. 22, 4/Sl 211.211-1

SSES-PSAR

.) The individual maintenance fill lines can be isolated to permit on ECCS systems and individual loops'f a system without affecting the other loops. See revised Subsection 6.3. 2 2. 5.

d) Due to the very small amount of continuous make-up required no interlocks are provided to give priority to "keep-full" function of the Condensate Transfer System's lines.

ECCS fill e) See revised subsection 6.3. 2.2.5.

f) The water events which have occurred in plants with NRC as ECCS fill hammer Licensing Event Reports (LER) .

BHR systems are documented and transmitted to the These are kept on file at the NRC. See Table 211.211-1 for a tabulation of water hammer events based on the General Electric Company.

LER information on file with Rev. 17, 9/80 2'l1. 211-2

SSES-FSAR Provide data to verify that representative HPCI active components (in particular, the pump) have been "proof-tested" under the most severe operating conditions that are anticipated. The service life and the maximum expected operating time accumulated during the service life of that HPCI pump should be specified.

RESPONSE

The HPCI pump for Susquehanna SES is similar in design and fabrication to pumps that have been installed and operated in BWR plants for several years.

While they have never been called upon to function during a DBA, these pumps are periodically tested in operating plants and have been shown to perform satisfactorily.

Each pump is tested at the vendor's plant for hydraulic performance and freedom from vibration. This is in addition to the tests and inspections performed during the fabrication of the pumps The severe operating conditions to which the pumps are exposed are temperatures to 148 F ambient, maximum expected post-DBA radiation levels and dynamic loads due to the safe shutdown earthquake and hydrodynamic effects associated with the DBA. The pumps are mainly fabricated of metallic materials which will not be degraded by the expected post-DBA temperature and radiation environment. The non-metallic gaskets and seals are made of materials with a demonstrated resistance to the post-DBA environment. The dynamic load inputs are addressed analytically and evaluated against appropriate criteria to assure operation of the pump while undergoing dynamic loading.

The above assures that the expected service life will exceed the expected operating time of approximately 550 hours0.00637 days <br />0.153 hours <br />9.093915e-4 weeks <br />2.09275e-4 months <br />.

A breakdown of expected operating hours for several events du'ring the life of the pump is provided below:

Event 0 eratin Time (Hours)

Shop Testing 2 Preoperational Testing 10 Monthly Testing 40 Yearly Testing 480 Post-LOCA 12 Shutdown N/A The assumed operating time for post-LOCA is 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for the HPCI pump. The low pressure RHR and CS systems take up the'core Rev. 22'/81 211.226-1

SSES"FSAR cooling within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after incipient LOCA event and maintain the long term core cooling of post LOCA subsequent to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> period.

G E stated that the ECCS pump motors meet the environmental q ualification requirements of the DOR guidelines and IEEE 323-1971.

Prior to June 30, 1982, further qualification work will be preformed to bring these items up to at least the level of IEEE 323-1971 per NUREG 0588 Category II.

Rev. 22 4/81 211.226-2

SSES-FSAR UESTION 211.260:

Identify the Failure Mode and Effect Analysis for evaluating the control rod drive system which you state is provided in Appendix 15A.

RESPONSE

Subsection 4.6.2 has been revised to state that The Nuclear Safety and Operational Analysis is presented in subsection 15A.6.5.3.

Rev. '22 4/81 211.260-1

SSES-FSAR QUESTION 211.262:

For the "recirculation pump seizure" accident, coincident loss of off-site power is not simulated with the assumed turbine trip and coastdown of the undamaged pump. Reanalyze this transient assuming coincident loss of offsite power and incorporate this reanalysis with that previously requested in Q211.120.

RESPONSE

The event severity of a coincident loss of offsite power with the postulated recirculation pump seizure accident is bounded by the analysis of "Loss of AC Power" as shown in Section 15.2.6. The only difference between these two events is the core flow coastdown rate, The flow coastdown rate during the pump seizure event coincident with a loss of offsite power is faster than that during the loss of AC power transient. The loss of AC power causes this event to become a pressurization event. The faster flow coastdown for pressurization events are less severe because of negative void reactivity coefficient. If the loss of offsite power were coincident with the high water level turbine trip, the resulting accident would be less severe than the one analyzed in the FSAR. This is due to the fact that the recirculation pump trip will occur earlier in the former accident.

To discuss the effect of core coastdown rate on CPR, the following is presented. Core coastdown rate has an effect on the change in CPR. This effect has two critical components which vary inversely with each other.

The inverse relationship exists between the heat generation rate (neutron flux) and the heat dissipation rate (thermal hydraulics), The faster the coastdown rate, the faster the neutron flux drops, but, the slower the residual heat in the fuel is dissipated.

The events in Chapter 15 'are analyzed to conservatively account for this relationship with regards to the change in CPR-Rev. 22, 4/81 211.262-1

g,>>6:

SSES-FSAR From the discussion of single failures for the "inadvertent HPCI startup" transient, it is indicated that a single failure of the pressure regulator or level control will aggravate the transient, resulting in reduced thermal margins. Provide the HCPR and peak vessel pressure values that result for this event with the most limiting of the above single failures considered in the analysis.

RESPONSE

In the event of the "inadvertent HPCI startup" transient, neither the pressure regulator nor the level controller is expected to fail because both systems are in normal continuous operation at the time of the hypothesized event, and no significant change in their function is demanded by the event. They should simply continue their normal function.

Inadvertent startup of the HPCI results in a mild pressurization. Upon pressurization due to the addition of cooler water into the feedwater sparger, the pressure regulator tends to regulate the vessel pressure by adjusting the position of the turbine control valve. When an active failure of the regulator system is considered, such that the turbine control valves would not open, further pressurization would result which would lead to an event similar to the "pressure regulator failure-close "transient (15.2.1) No significant change in thermal margin protection would occur (< .01 CPR change).

Because of the addition of the cooler water in feedwater sparger, the level control system tends to reduce the feedwater flow to maintain the normal water level. When an active failure of the level control system is considered, the water level would continue to rise. .This situation is similar to the "feedwater controller failure-maximum demand" transient (15.1.2) and results in a similar CPR change.

Since the HPCI startup does not challenge these control systems significantly, beyond their normal contxol functions, the independent, simultaneous failure of either is considered extremely unlikely.

Note: The word "aggravate" used in the text does not mean a worse thermal margin. It rather implies an undesirable action (e.g.

turbine trip) which may result in reactor scram and shutdown.

RBV. 22, . 4/81 211.276-1

SSES-FSAR Our position on the emergency core cooling systems (ECCS) is that these systems should be designed to withstand the failure of any single active or passive component without adversely affecti their long-term cooling capabilities. ln this regard, we are concerned that the suppression pool in boiling water reactors (BWR's) may be drained by leakage from isolation valves which may be rendered inaccessible by localized radioactive contamination following a postulated loss-of-coolant accident (LOCA). Accordingly, indicate the design features in the Susquehanna facility which will contain leakage from the first isolation valve in the ECCS lines taking water (suction lines) from the suppression pool during the long-term cooling phase following a postulated LOCA.

RESPONSE

The ECCS is designed to withstand the failure of any single active or passive comoonent without adversely affecting the long-term cooling capabilities. Any leakage from ECCS systems can be isolated and contained. The design features in Susquehanna that assure this capability are described in response to FSAR Question 211.10.

Rev. 22, 4/81 211.295-1

SSES-FSAR QUESTION 221.14:

Your response to Question 221.1 is unacceptable. The staff believes that the state-of-the-art has progressed such that effective LPM systems can be installed in commercial LWRs. The rationale for this is documented in draft Regulatory Guide 1.133 (Loose-Part Detection Program for the Primary System of Light-Water-Cooled-Reactors). Additional rationale clarifying the staff position c'n also be found in a letter, Vassallo to J. E. Mecca (Pugent Sound Power and Light Company) "Skagit Nuclear Power Project, Units 1 6 2" dated July 20, 1978 (Docket Nos. 50-522/523) available in the NRC public document room. A number of LWR's, including BWR's, at thesame stage of licensing as Susquehanna, have committed to the installation of a LPM system. In addition, it is required by the staff that a LPM system be installed and operational prior to startup of the reactor. Therefore, please provide the information requested in Q221.1.

RESPONSE

The Susquehanna SES Loose Parts Monitoring System is discussed in subsections 7.7.1.12 and 7.7.2.12.

Rev. 22, 4/81 221.14-1

SSES-PSAR The response to Question 221.9 is unacceptable. The applicant should commit to submit a report describing the computer program used for core thermal-hydraulic analysis prior to issuance of an operating license for Susquehanna. The report should provide the code description, the calculational methods and empirical correlations used, a sample application and code verification through comparison with experimental data. 1

RESPONSE

The computer program cited in Subsection 4.4.4.5 is named TSCOR.

Various versions of this code have been used by the General Electric Company for over a decade to perform detailed core, steady state, thermal-hydraulic analyses.

The XSCOR computer program is used as the basis for the steady state thermal-hydraulic module in the GEBS/PANAC three-dimensional BWR core simulator. The models and non-proprietary correlations are described in Chapter 4 of the BWR Core Simulator Licensing Topical Report (NEDO-20953, Hay 1976).

Rev. 22, 4/81 230.1-1

SSES-FSAR The response to Question 221.2 is unacceptable. Question 2 requested assumptions used for amount of crud used in design calculations and the sensitivity of CPR and core pressure drop to variations in the amount of crud present. Merely stating that "a conservative amount of crud is deposited on the fuel rods and fuel rod spacers" does not begin to answer this question. The question also asked for a discussion of how crud buildup in the core would be detected;

'o discussion is provided.

RESPONSE

In general, the CPR is not affected as crud accumulates on fuel rods

,(References 1 and 2). Therefore, no modifications to GEXL are made to account for crud deposition. For pressure drop considerations, the amount of crud assumed to be deposited on the fuel rods and fuel rod spacers is greater than is actually expected at any point in the fuel lifetime. This crud deposition is reflected in a decreased flow area, increased friction factors, and increased spacer loss coefficients, the effect of, which is. to increase the core pressure drop by approximately .1.7 psi, an amount which is large enough to be detected in monitoring of core pressure drop.

It should be noted that assumptions made with respect to crud deposition in core thermal hydraulic analyses are consistent with established water chemistry requirements. More detailed discussion of crud (service-induced variations) and its uncertainty is found in Section III of Reference 3.

Reference:

1. McBeth, R. V., R. Trenberth, and R. W. Wood, "An Investigation Into the Effects of Crud Deposits on Surface Temperature, Dry-Out, and Pressure Drop, with Forced Convection Boiling of Water at 69 Bar in an Annular Test Section", AEEW-R-705, 1971.

2. Green, S. J., B. W. LeTourneau, A. C. Peterson, "Thermal and Hydraulic Effects of Crud Deposited on Electrically Heated Rod Bundles", WAPD-TM-918, Sept. 1970 .

3. "General Electric Thermal Analysis Basis (GETAB): Data, Correlation, and Design Application", General Electric Company, January 1977, (NEDO-10958A).

Rev. 22, 4/81 230.2-1

SSES-FSAR Your response to question 221.13 is incomplete. Since the operational design guidelines are exceeded for some operating conditions, Figure 4.4-6 should be revised to show decay ratios as a function of rod position, recirculation flow and power. Figure 4.4-6 as currently presented is not sufficiently detailed for use in inferring operational boundaries.

RESPONSE

The operational design guideline is not intended for use in defining operational boundaries. It is used to determine the range of optional operation in the automatic flow control mode. Current guideline is the decay ratio 0.5. It is clear from Figure 4.4-6 that most of the operating domain meet the guideline. It should be noted, however, that power/flow condition which has a decay ratio greater than the guideline can always be operated in the manual flow control mode.

Although GE does utilize design stability guides to optimize BNR operation and performance from an availability considerations, application of these guidelines is not considered to be a necessary requirement to demonstrate'an acceptable and licensable configuration.

The criterion used with respect to safety is that the calculated decay ratio be less than 1.0 over the expected range of operation. This has been demonstrated for Susquehanna unit. Operational guides have been deleted from Figure 4.4-6.

Rev. 22, 4/81 230.3-1

SSES-FSAR Your response to Question 221.15 is unacceptable. You reference NEDO-10958-A for a discussion of the uncertainties and their bases.

The staff evaluation of NEDO-10958 states "The estimated value of the uncertainties and the basis for the value depend on the specific design and equipment of each reactor and will be evaluated for each reactor at the time Technical Specifications are issued." Information to support the uncertainty values for Susquehanna must be submitted prior to issuance of a safety evaluation report for Susquehanna.

RESPONSE

A general discussion of the bounding statistical analysis uncertaintie shown in Table 4.4-6 is given in the GETAB Licensing topical report (Reference 1). Of these uncertainties, all except that of critical power are unaffected by the two water-rod assembly design. The GEXL critical power predictability for the 8x8 two water-rod design has been shown to be similar to the standard one water-rod design (see the response to Question 221.3); the value for this uncertainty cited in Reference 1 (1 =3.6%) is conservative with respect to both one water-rod and two water-rod designs.

Additional information concerning the remaining uncertainties in Table 4.4-6 and the bases used in the derivation of those uncertainties is contained in the Licensing topical report "Process Computer Performance Evaluation Accuracy" (References 2, 3 and 4). As stated therein, "the analysis was performed...for measurements systems typical of (or conservative with respect to) the BWR4-6," and is therefore directly applicable to Susquehanna.

References:

1. "General Electric Thermal Analysis Basis (GETAB): Data, Correlation, and Design Application," General Electric Company, January 1977 (NEDO-10958A).

2. J. F. Carew, "Process Computer Performance Evaluation Accuracy,"

General Electric Company, June 1974 (NEDO-20340).

3. J. F. Carew, "Process Computer Performance Evaluation Accuracy Amendment 1," General Electric Company, December 1974 (NEDO-20340-1).

4. J. F. Carew, "Process Computer Performance Evaluation Accuracy Amendment 2," General Electric Company, September 1975 (NEDO-20340-2).

230.4-1 Rev. 22, 4/81

SSES-FSAR

• UESTION 230.8:

The steady-state operating limit for the Minimum Critical Power Ratio (MCPR) is 1.25. This value is calculated based on REDY model described in NEDO-10802. The results of three turbine trip tests performed at the Peach Bottom-2 have revealed that in certain cases the results predicted by REDY model are non-conservative.

The General Electric Company's new ODYN for use in transient analyses has been approved. Accordingly, the applicant is required to reanalyze prior to criticality the following transients with ODYN: 1) generator load rejection/turbine trip,

2) feedwater controller failure~aximum demand and 3) main steam isolation valve closure with position switch scram failure. If another event should be more limiting than those listed above, the other event should reanalyzed with ODYN.

The reanalyses should include CPR calculation and demonstrate that the operating limit for MCPR is not less than 1.25.

RESPONSE

The Susquehanna SES ODYN submittal is scheduled for the second quarter of 1981.

UESTION 281.17 It is our position to meet Section C.l of Appendix A to BTP-ASB 9.5-1 automatic smoke detectors be provided in the following areas and that they alarm and annunciate in the control room. Fire detectors should, as a minimum, be selected and installed in accordance with NFPA 72E, "Automatic Fire Detectors".

Reactor Building Fire Zone Area Elevation

l. 1-1G Sump pump room 645-668

2. 1-2A Access area 670-683

3. 1-3A Access area 683-719

4. 1-3B Access area 683-719

5. 1-3C Access area 683-719

6. 1-4A Containment access area 719-747

7. 1-4B Pipe penetration room 719-733

8. 1-4G Main steam piping 717-816

9. 1-5A Fuel pool pumps 6 heat exchangers 749-771

10. 1-5B Valve access area 761-771

11. 1-5D RMCU Pumps 8 heat exchangers 749-766

12. 1-5E Penetration room 749-777

13. 1-6A Area 'ccess 779-797

14. 1-6D HSV equipment room 779-797

15. 1-6E Recirculation fans area 778-797

16. 1-6F Spent fuel pool 779-797

17. 0-6G Surge tank vault 775-797

18. 1-7A HRV fan and filter rooms 779-816

19. 1-7B Recirculation fan room 799-816

20. 0-8A Refueling floor 818-873 partial

RESPONSE

Each of the areas listed are being examined to determine if they contain or present a fire exposure hazard to safety-related systems necessary to accomplish or maintain a safe-shutdown condition. Additional smoke detection will be provided in those areas satisfying either criteria. This l

is documented in Revision to the Pire Protection Review Report.

Rev. 20, 2/81 281.17-1

SSES-FSAR UESTION 313.1 The classification system for emergency conditions used by PPSL is identified in the emergency plan, as is the system used by the Luzerne County Office of Civil Defense and the PA Bureau of Radiological Health. While these classification systems appear compatible, the terms used are different and no direct comparison is made in the plan. Provide such a comparison between the classification terms used by PPM and those used by the offsite agencies, either in the text of Section 4 of the plan, or on Figure 6.1.

RESPONSE

o As established in 10CFR50 Appendix E and NUREG 0654/FEMA REP l, Rev. l, PPSI,, State, and Local Emergency Plans have incorporated the same emergency classification system. The classification system outlined in Section 4.0 of the Susquehanna SES Emergency Plan Rev. 2 dated October 1980 is identical to the state and local emergency classification system.

Rev. 22, 4/81 313.1-1

SSES-FSAR UESTION 313.6 Concerning protective actions, describe steps taken to make available on request to occupants in the low population zone, information concerning how the emergency plans provide for notification to them and how they can expect to be advised what to do.

RESPONSE

The following methods will be implemented to ensure information on Emergency Planning is transmitted to the Emergency Planning Zone residents. Annually, a full page ad, summarizing the instruction and action to be taken by the EPZ residents in the event of an emergency will be published in the local newspaper.

Annually, printed instructions and evacuation maps will be distributed to residents within the EPZ.

Evacuation maps and printed instructions will be printed in all telephone directories within the EPZ. An alert .warning siren system controlled by the county Emergency Operations Centers will be installed within the EPZ to provide early notification to the public. This system will alert the public to tune to the local Emergency Broadcast System for further information and direction.

Rev. 22, 4/81 313.6-1

SSES"FSAR UESTION 313.7 Describe the training provided the appropriate staff members of the Berwick Hospital to show that they are prepared and qualified to handle radiological emergencies.

RESPONSE

Key members of the Berwick Hospital Staff will be initially trained at the Oak Ridge "REACTS" course. Annual training of appropriate Berwick Hospital personnel will be provided by a consultant experienced in the handling of contaminated/irradiated injured personnel.

Annual drills of Berwick Hospital staff members will be conducted and critiqued to ensure their ability to handle radiological emergencies.

Rev. 22, 4/81 313.7-1

SSES"FSAR UESTION 313.8 Provide a commitment to conduct annual exercises to test the adequacy of the emergency plan and the implementing procedures.

See Regulatory Guide 1.101, Annex A, at Section 8.1.2.

RESPONSE

The second sentence of the first paragraph in Section 8.1.2 of the Emergency Plan will be changed to read: "An initial exercise prior to loading of fuel for Unit 1 and annual exercises thereafter will involve a scenario appropriate to a Site Emergency or General Emergency Condition."

These exercises will be conducted using the guidelines of 10CFR50 Appendix F 3.7.3-l979.

NUREG 0654/FEMA REP 1 Rev. l, and ANSI/ANS-Rev. 22, 4/81 '313.8-1

SSES-FSAR g

When will settlement readings on the ESSW Pumphouse Basement (FSAR Table 2.5-8) be provided?

RESPONSE

The response to this question is given in 362.22.

Rev. 22, 4/81 362.9-1

SSES-FSAR Provide a map of the site clearly showing the topography as altered by the plant. Note that FSAR Figure 2.4-1 is inadequate because it is very difficult to see the contours in the vicinity of the plant.

RESPONSE

Figure 2.5"24 has been revised and shows all the present roads and finished grading for both Units 1 and 2.

Rev. 22, 4/81 '

371.19-1

SSRS-FSAR gmSTXON-421.442=.

Zt has "ome to our atantion that some applicants ail not intend to "onduct confirmatory tests of some Distcibutio syst ms ani transformers suoplying pow r to vital buses as reguiceD by Position 3 of Regulatory Guide 1.68, and more specificxtlly by Pact 4 of the staff position on Degraded grid voltage (applied to all plants in li=ensing ceview by the Power Systems Branch sin"e 1976) . Part 4 of the d gcaDeD gciD voltage position states as f olio ws:

Tha voltage leveLs at the safety-related'uses should be optimized for the full loaD and mininum load conditions that ace expecteD thcoughout th anticipated range of voltage variations of the offsite power source by appropriate aD justment of the voltage tap settings of the intervening tcansfocmecs. He require that the adequacy af the Design in this regard be verified by actual measurement and by correlation of measured values with analysis results. Provide z Description of the method foc making this vacification; before initial reactor power opecation, pcovide the do"umentation requiceD to establish that this vecification has been accomplished.'!

Your test description in FSAR .Chap.tec l4 does not contain sufficient detail for us t> determine if you intend to conduct such a test. It is our position that 'onficmxtory tests of all vital buses must be conducted including all sour"es of powec supplies to the buses Noiify your test Description to indicate that this testing will be conducted in accordance with Regulatory Guide 1 68 and the above citeD position..

BZSPOBSZ=.

Voltages recorded during the P100.1 Preoperational test (Subsection 14.2.12.1), will be reviewed and analyzed against design calcul'ations to assure optimal tap settings have been selected.

Rev. 22, 4/81 421.042-1

SSES-FSAR valves: and turbine stop, inte cept, and control val ves.

5o us Verify response times of branch steam line isolation.

5 Demonstrate adequate performance margins for shielding and penetration cooling systems capable of maintaining tern peratures of cooled components within design limits with the minimum design capability of cooling system components available (100/)

5. x. Demonstrate adequate beginning-of-I.ife performance margins for auxiliary systems required to support the operation of enqineered safety features or to maintain the environment in spaces that house enqineered safety features. Engineered safety features will be capable o performing their design functions over the range of design caoability of operable components in these auxiliary systems (50%, 100%) .

5. z. Demonstrate that process and effluent radiation monitoring systems are responding correctly.

5. c.c Demonstrate that gaseous and liquid radioactive waste processinq, storage, and release systems operate in accordance with design.

5.f.f Demonstrate that the ventilation system that serves the main steam line tunnel maintains temperature within the design limits.

5 h.h Demonstrate that the dynamic response of the plant to the desiqn load swings for the facility.

5o isla Demonstrate that the dynamic response of the plant is in accordance with design for closure oX reactor coolant system flow control valves.

5.1.1. Demonstrate that the dynamic response of the plant is in accordance with design requirements for turbine trip.

QESPOQS~

Preoperational tests of safety related systems are described by the test abstracts provided in subsection 14-2-12-1. Specific detailed guid elines for testinq such a loss of power, air, etc.

are described in the startup administration manual Section 7.5.

Loss of power is tested if it causes an evolution to occur within the system such as switching automatically to a different power source. Loss of air testing is performed by placing the valve in its non-failed position by normal actuator operation, then isolating the actuator air supply, blet ding off air pressure and verifying valve movement to the failed position. Each automatic containment isolation valve is tested in the system pre-op test. for proper oper-ation and closure timing as required by the design sections of the FSAR. Leak detection systems such as steam leak detection are tested in the system pre-ops affected by the detection system.

Rev. 22, 4/81 423. 12-5

SSES-FSAR The response to item 423.14 indicates that, testing described in Regulatory Guide 1.80 sections C.7 through C.10 will not be done since the testing will have already been done during "various system preoperational tests". Either provide test descriptions that show testing equivalent to that specified in regulatory positions C.8, C.9, and C.10 will be performed, or modify your preoperational test program to include an integrated loss of air test and provide an abstract of that test.

RESPONSE

See revised response to Question 423.12.

Table'23.28-1 lists air operator valves/HVAC dampers which are tested for loss of air. Preoperational tests within which the loss of air testing is accomplished is also provided in Table 423.28-1.

Further testing is performed for the ADS/SRV valves as follows:

1. Verify minimum capacity of accumulator in acceptance criteria.

2. Verify ADS/SRV's are operated from their respective accumulator/

supply with other supplies depressurized.

3. Record pressure at which an open valve begins to close for safety/

relief valves and verify valve fails to close on loss of air.

4. Verify an open ADS valve is maintained open at accumulator pressure of 75+0-2 PSIG and fails closed on loss of air.

Rev. 22, 4/81 423.28-1

INST. AIR OR PRI.

SYSTEM VALVE NO. PREOP. NO. CONT. INST. GAS RHR 1-Ell<<P050A;B P49.1 ~

Inst< Air 1-E11-P122A,B Inst; Gas

'-E11-F051A,B Inst. Air 1-Ell<<F052A,B C

CO 1-E11-P053A,B l-E11-F305A,D 1-'Ell-PlllA,B 1<<Ell-F129A,B .

l-E11-F132A,B 1<<E11-F136,F137,P140 HV-E51-'17088 ' '.. P50;1' 'Inst

'Gas'nst;

'V-E51-1F025;1P026 Air .

W-E51-1F004,1F005

'HV-E51-1P054

~

Core Spray . HV-E21 lF006A,B $ 51.1

~ 1N-E21~1F037A, B ~ ~

':ln'st; 'Gas HPCI HV-E41-.1F028,1F029 '52;1' '

' Inst; Air HV>>E41-1F025,1P026 ~

'HV-E41-1P057,1P100. ~ ~ ' '1F100'Ga's' 0the s.Ins't'ir CRD..- C12-POoaA,B....... ~ ~ ~ ~

P55sl Inst. Air XV-lP010, 1P011 HV-B31-1P019;1P020 .Both + ' ~ ~ \ ~ ~ ~ ~

INST. AIR OR PRI SYS VALVE NO. PREOP NO. CONT. INST. GAS Pire Protection XV-12244,45;46,48,49 'P13 .Inst; 'Air XV-12205A, B, C XV-02247A,B;C XV-02248.

XV-02215 liv-11315 P14 'Inst;.

Air'B HVAC llD17534A,B,C,D,E,ll',ll All 1 ~

P34;X Inst;'A'ir Hg17514A,B All *

+'ID17502AjB;

\

llD17530A, B,'lD17531A' ~

llD17564A,B; BD17524A,B.A11 IlD17576A,B; -)lD17586A;B All*

llD17508A,B ~ .Both +-

llD17651. .

BDID17603A;B BDID 17604A;B;- BDID 17605A;B ..

~ ~

BDID 17606A;B; BDID 17609A;B.

~ 7 a I 17659A B- n 6

~ ~ ~ ~

BDID 17668A,B; BDID 17669A,B BDID. 17670A,B;. QDID 1761A,B.....

BDID.17674A,B; BDID17675A.,B..

INST. AIR OR PRI.

SYSTEM VALVE NO. PREOP. NO. CONT. INST. GAS RWCU i HV-14506A;B; 14507A,B. . P61'.3.'nst; Air a"

o

" 'ii )

HV-14508A,B; 14510A,B HV-14511A B'4512A B HV-14513A,B; 14514A,B '

HV-14566A,B; 14522....

HV-14523, 14528,14516 HV-14518, 14519; 14520 '

HV-14521, G33-1F033 Liquid-Radwast 16108A1; 16116Al ~ ~

P69'.1'Ihst; 'Air' 16108A2, 16116AL Both '* e

~ /

Containment HV-17521,23,24,22,25'A11 ~ ~

'P73'.1' Inst.'Aii' Recirculation HV-15704 05 14'AllV-15703;13

~ ~ ~

/ ~ ~ ~ ~

'0

~ ~

/

~ ~

INST- AIR OR PR SYSTEM VALVE NO. PREOP. NO. CONT. INST. GAS R.B. HVAC PDD 17501A;B; HD17511A;9 '34'.'1'nst; 'Air HD17521A B; HD17513A 9 HD17518A,B; HD17516 HD17523A,B; HD17528A,B PDD17578A,B; HD17526 ':

HD17566A~ B~ )'ID17588Af'9 HD17538A,B RB Chilled Mater TV-18726A1,A2,B1,92 .P34.2. Inst; Air TV-18741A; 9, C, D

~ ~

TV<<18743A, B TV-18751A 9 C D

\

~ TV-18753A,B ~

TV-18764A,B TY-18771A;9;C,D

~

TV-18781A1 A2,91 92,A11 + Inst;.Gas.

HV 18782A1 ~A2 ~ 91 ~92~A1 1 HV-18791A1, .A2,91, 92h11

• HV-18791Alg A2,91; 92All .* ~ ~

INST. AIR OR PRI.

SYSTEM VALVE NO. PREOP. NO. CONT. INST. GAS Control Structure HDM&7802A B 'oth

• 0 O.l Q

HVAG HDM-07833A, B; HDM-07824A2, B2 HDM-07824 A4 B4 HDM-078S 'B HDM-07872A,B; HDM-07873A,B All *

'V-07813A,B TV-08602A,B P30..2. ~ .'....

Feedwater '

10604A B C 10640 '106'41 14107A,B 10650

'10606A,B;C 10604A,B;C '

0 6 6 3A'1 ~ A2 ~ B 1 ~ B2 7 C 1 ~ C2 10664A;B,C .

~ ~ ~ ~ ~

~ ~

SSES-FSAR Our review of recent licensee event reports disclosed that a significant number of reported events concerned the operability of hydraulic and mechanical snubbers. Provide a description of the inspections or tests that will be performed following system operation to assure that the snubbers are operable. These inspections or tests should be performed preoperationally if system operation can be accomplished prior to generation of nuclear heat.

RESPONSE

Existing QA records on the construction installation and inspection of safety related snubbers will be assembled into a package for review by the Superintendent of Plant. This package will provide assurance that the preoperational condition of the snubbers is acceptable and that they are installed in accordance with design.

After system preoperational testing and prior to fuel load, snubbers will be visually examined and manually tested fcr freedom of movement over the range of stroke in both compression and tension.

This meets the requirement of ZE Bulletin 81-01 Rev. 1. No hydraulic'nubbers are utilized in safety applications at Susquehanna SES.

Rev. 22, 4/81 423.40-1