Forwards Revision 22 to FSAR.

REGOLAT'ORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:8103230429 "OOC ~ DATE: 81./03/20 NOTARIZED: HO

FACIL:50 Susquehanna Steam Electric Station< Unit ir Pennsy'lva388 usEruehanna Steam Electric Stationi Unit 2r Pennsylva

AUTHOR'FFILIATIONPennsylvania Power 8 Light Co ~

RECIPIENT AFFILIATIONLicensing Branch 1

DOCKET ¹0500038705000388

SUBJECT: Forwards revised pages to FSAR ~

0ISTRISOTION COOS: ROOTS COPIES RECE IVES ILTR 3, ENCL lg SIZE: I+8'~TITLE: PSAR/FSAR ANDTS and Related Correspondence

NOTES:Send I8,E 3 cooies FSAR 8 allamends'endI8E 3 copies FSAR 8 all amends'500038705000388

RECIPIENTID CODE/NAME

ACTION: A/D LICENSNGRUSHBROOKgtvI ~

INTERNAL: ACCID EYAL RR26CHKH ENG BR 08CORK PERF BR 10K%ERG PREP 22GEOSC IKNCES 14HYD/GEO 3R 15I8,E 06LIC QUAL BRMECH KNG 8R 18NRC POR 02OP LIC BRPROC/TST REV 20RAD ASSESS RR22

IÃ F IL 01CY NG BR25

COPIESLTTR'ENCL

1 01 0

1 11, 1

1 1

01 1

2 23 31 1

1 1

1 1

1

1 1

1

1 1

1 1

RECIPIENTIO CODE/NAME

YOUNGBLOODEBSTARKgR ~ 04

dUX SYS SR 07CONT SYS 8R 0'?EFF TR SYS BR12EQUIP QUAL BR 13PULI FACT ENG BRI8C SYS BR ieL IC GUID BR'LIATL KNG BR 17MPAOELDPOWER SYS BR 1?QA BR 21REAC SYS BR 23SIT ANAL BR 2aSYS INTERAC BR

COPIESLTTR ENCL

1 01 1

1 1

1 1

1 1

3 31 1

1

1

1

1 01 0

1

1 1

1

1

1 1

EXTERNAL: ACRSNSIC

2705

16 161 1

LPDR 03 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. CURTISVice Presirtent. Engineering 8 Construction-Nuclear770.5381

March 20, 1981

Mr. B. J. YoungbloodLicensing Project: Branch 81Division of Project ManagementU.S. Nuclear Regulatory CommissionWashington, DC 20555

SUSQUEHANNA STEAM ELECTRIC STATIONFSAR CHANGESER 100450 FILE 841-2PLA-662

Enclosed please'ind forty (40) copies of changes to the Susquehanna SteamElectric Station Final Safety Analysis Report. Effected FSAR Sections arelisted on the attachment to this letter.

Very truly yours,

N. W. CurtisVice 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 theseismic requirements for the Safe Shutdown Earthquake, asdescribed in Section 3.7.

NA - The seismic requirements for the Safe ShutdownEarthquake 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 programdescribed in Chapter 17.

N - Not within the scope of lOCFR50, Appendix B.

8) The classification of the control rod drive water return linefrom the reactor vessel through the third isolation valvewill 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 thecertification requirements:

The manufacturer of the turbine stop valves, turbinecontrol valves, turbine bypass valves, and main steamleads from turbine control valve to turbine castingshall use quality control procedures equivalent to thosedefined in General Electric Publication GEZ-4982A,"General Electric Large Steam Turbine-Generator equalityControl Program".

2. A certification shall be obtained from the manufacturerof these valves and steam leads that the quality controlprogram so defined has been accomplished.

10) 1. Instrument and sampling piping from the point where theyconnect to the process boundary and through the processshutoff (root) valve(s), isolation valve(s), and excessflow check valve, when provided, will be of the sameclassification as the system to which they connect.

2. All instrument lines which are connected to the reactorcoolant pressure boundary and are utilized to actuatesafety systems shall be Group B from the process shutoff(root) valve(s), isolation valve(s), or excess flowcheck valve, when provided, to the sensinginstrumentation.

3. All instrument lines which are connected to the reactorcoolant pressure boundary and are not utilized toactuate 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 sensinginstrumentation.

4. Other instrument lines:.

a) Those connected to special equipment or Group Dsystem pressure boundaries and utilized to actuatesafety systems will be Group C from the systempressure boundary through the process shutoffvalve(s) to the sensing instrumentation.

b) Those connected to Group B and Group C systems andutilized to actuate safety systems shall be of thesame classification as the process system to thesensing instrumentation.

c) Those connected to Group B and Group C systems andnot utilized to actuate safety systems will be ofGroup D classification except for those Group Csystems by GE utilizing capillary (filled andsealed) instrument lines.

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

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

ll) The HPCI and RCIC turbines do not fall within the applicabledesign codes. To ensure that the turbine is fabricated tothe standards commensurate with their safety and performancerequirements, General Electric has established specificdesign requirements for this component.

12) The hydraulic control unit (HCU) is a General Electricfactory assembled, engineered module of valves, tubing,piping, and stored water which controls a single control roddrive by the application of precisely timed sequences ofpressures and flows to accomplish slow insertion orwithdrawal of the control rods for power control, whileproviding rapid insertion for reactor scram.

Although the hydraulic control unit is field installed andconnected to process piping, many of its internal partsdiffer maikedly from process piping components because of themore complex functions they must provide. Thus, although the

THIS FIGURE HAS BEEN INTENTIONALLYLEFT BLANK

REV. 22, 4/81

SUSQUEHANNA STEAIN ELECTRIC STATIONUNITS 1 AND 2

FINALSAFETY ANALYSISREPORT

THIS FIGURE HAS BEEN INTENTIONALLYLEFT BLANK

FIGURE 3. 6-9

SSES-FSARTABLE 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

Se

RCIC Pump

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 Calculationsaf. High Density Spent Fuel Storage Racks

Rev. 22, 4/81

TABLE 3.9-2(s) — (page 1 of 2)

NEW FUEL STORAGE RACKS

CRITERIA

1. NEW FUEL STORAGE RACKS

LOADING

FAULTED CONDITION "A"

LOCATIONALLOWABLESTRESS (.7 ULT)

CALCULATEDSTRESS

Stress due to normal upsetor emergency loading shallnot cause a failure so as toresult in a critical array.

l.2.

3.4.

Dead LoadsFull Fuel Load inrackS.S.E.Thermal (not appli-cable)

1. Beam (Axial) l. 26,0008/in22

2. Beam (Trans.) '2.'6,000/I/in>3. Combined = 3. 26, 0008/in

1. 18,9058/ig 2

2. 7,005///in2. 25,9108/in

2. SOURCE OF ALLOWABLE STRESS (.7 ULT)

a ~

b.C ~

d.e.

ASTM B308 Alloy 6061-T6ASME Code — Boilers and Pressure Vessels, Sect. III, NAProduct Safety Standards for Bt&-6-Mark III, Sect. VI, A. (3)ASME — Pressure Vessels and Piping: Design and Analysis, Volume One, Page 69.ASTH code for Boilers and Pressure Vessels was selected on the premise that data used from this sourcewould 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 loadat highest expected pool temperature. Earthquake stresses obtained by square root of the sum of- thesquares method for a response due to tri-axial excitation. Stress given is the highest in the totalstructural array.

4. NEW FUEL STORAGE RACKS FAULTED CONDITION"B"

Stresses due to normal upset (See Below, Par.~)or emergency loading shallnot cause a failure so as toresult in a critical array.

(Location-SeePar. 6, Below)

Not Applicable Not Applicable

FAULTED CONDITION "B": Condition "B" is an emergency condition in which the stress limit is equal tothe yield strength at 0. 2% offset. The racks were tested to determine theircapability to safely withstand the accidental, uncontrolled, drop of a fu'elbundle 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 inpairs 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 wereX-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 eachtest. 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 impactcaused by a load dropped from a height of 5.33', (Test f/19). Accelerometerreadings 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 spectrawas performed on a simplified model consisting of 6 racks (1 quadrant). 'Iheresulting loads on the corner module were extracted and a more detailedanalysis per forned.

STATIC ANALYSIS:

A detailed finite element (1364 elanents) model of the corner module wasdeveloped and a static analysis performed using the loading results of thedynamic analysis. The section descriptions, allowable stresses and stressratios 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 dueto fuel rattling. A canparison of the support loads from the fuel rattlinganalysis with those of the response spectrum analysis showed that the fuelrattling 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 bottomcasting at the middle.

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

Rev. 22, 4/81

SSES — FSARTABIE 3.9-2 (af ), page 2 of 2HIGH DENSITY SPENT FUEL RACK

SUMMARY OF RESUL'LS FOR THE DETAIIZD MODEL ELEMENTS

NORMALAUlMABLE

STRESSESNORMAL OPERATING CONDITION

DESIGN ACCIDENT ANDEKTREME ENVIRONMENTAL

CONDITIONS

SECT.NO. SECTION DESCRIPTION Fa Fby Fbx

fa fb fbxFbx

STRESSRATIO

(1)

fbxFby

MAXSTRESS

RATIO(l)

4 Bottom Grid Inner Sect. 8550

Bottcm Grid OuterSection Near Leg

9650

1 Top Grid Outer Section 9941

2 Top Grid Inner Section 9420

3 Bottom Grid Outer Sect. 8830

15760 15760 .026

15760 15760 .057

15760 12120 .062

15760 12120 .005

15760 12120 .047

.009

.055

.248

.831

.249

.747 .78

.813 .93

.108 .42

.013 .85

.269 .57

.018

.040

.062

.005

.047

.006 .715 .74

.039 .766 .85

.248 .108 .42

.831 .013 .85

.249 .269 .57

Bottom Grid InnerSection Near Leg

9530 15760 12120 .046 .508 .248 .80 .046 .508 .248 .80

7 Bottom Grid Foot

8 Bottan Grid Foot

9 1/2" Plate

10 7/8" Plate

(1) Stress Ratio

10250

11020

3320

17370

15760 12120 .132

14180 14180 .161

Fv = 1390

F = 10970a bv fbx

Fa + %' Fbxx

Rev. 22, 4/81

(2) Plate Stress Ratio = f> fx+

.001 .13

.003 .16

99(2)

92(2)

.160

.195

0 .003 .16

0 .006 .20

76(2)

.92(2)

NOZEAllowable stresses arefactored up per Table 9.1-7aof the SSES-FSAR.

SS ES-FS AH

4 . 4 . 6 I N S TH H:.5 E N T A T I0 N R E Q 0 IH E i J E NTS

The reactor vessel instrumentation monitors he Key reac.orvessel operatinq parameters during planned operations. Thi-ensures suffi"ient control of the paramete=s. The followinqreactor 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=ialP 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 inSubsections 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 ElectricCompany, January 1977, (N"D0-10958A).

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

4. 4-3 H.C. Nartinelli and D. F.. Nelson, "Prediction ofPressure 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-PhasePressure Drop," Heat Tran"fer Conference (Los Angeles),AECLE, Preprint No. 37, 1966.

4 4-5 Jens, R. H., and Lottes, P.A, Analysis of HeatTransfer, Burnout, Pressure Drop, and Density Data forHigh 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 andEng ineer inq, 30 p. 25, 19 67.

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

1.6

TOTAL CORE STAB ILITY

1.4

1,0ULTIMATEPERFORMANCE LIMIT

OI

L0

0.8

0.6

NATURALCIRCULATION

105'%OD LINE

0.4

02

00 20 40 80 120

PERCENT POWER

SUSQUEHANNA STEAM fLECTRIC STATIONUNITS 1 AND 2

FINALSAFETY ANALYSISREPORT

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 (105,0001b) is then treated as a static load in design.

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

6.2 ~ Evaluations of the CRDS

This subject is covered under nuclear safety and operationalanalysis (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 roddrive housing supports .is described below.. Purther descriptionof "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 wasevaluated in the mechanical design of the "ontrol rods. Theprimary materials,84" powder and 304 austenitic stainless steel, have been foundsuitable 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 actuatedfrom the main control room. A single failure ia any electricalsystem is analyzed regardless of whether the loss of a safetyfunction is caused by either component failing to perform arequisite mechanical motion, or component performing anunnecessary mechanical motion.

6.2.4.4 Tests and Ins ections

The containment isolation system is preoperationally tested inaccordance with the requirements of Chapter 14.

The containment isolation system is scheduled to undergo periodictesting during reactor operation. The functional capabilities ofpower operated isolation valves are tested remote manually fromthe control room. By observing position indicators and changesin the affected system operation, the closing ability of aparticular isolatioa valve is demonstrated.

A discussion of testing and iaspection, including leak tightnesstesting, pertaining to isolation valves is provided in Subsection6.2.6 and ia Chapter 16. Table 6.2-12 lists all isolationvalves.

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

Excess flow check valves (EFCV) shall be periodically tested byopening a test drain valve downstream of the EFCV and verifyingproper operation.

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

6.2.5 COMBUSTIBLE GAS CONTROL IN CONTAINMENT

The combustible gas control system is provided, in accordancewith the requirements of General Design Criterion 41 of AppendixA to 10CFR50, to control the concentration of hydrogen withiathe 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

Penetration Description

Inboard Isolation BarrierType Barrier Description/Test Valve No. Notes*

Outboard Isolation BarrierBarrier Description/

Valve No. Notes*

Exemptionto IOCFR50Appendix JRequired

X-I

X-2

X-2

X-2

X-2

X-3A

X-3B

Equip. access hatch B

Equip. access hatchuith personnel lock

Personnel lock barrel B

Personnel lock inner door B

Personnel lock outer door B

Spare

Primary ContainmentPressure Inst.(2)

Double 0-ring

Double 0-ring

Inner door/barrel

Double 0-ring

Cap

1>2

1,3

10

Outer door/barrel

Double 0-ring

1>2

1,3

10,11

X-3C

X-3D

X-4

X-5

X-6

X-7A

Spare

Spare

Dry@oil head accessmanhole

Dryuell head

Spare

CRD removal hatch

Main steam

A Cap

A Cap

Double 0-ring

Double 0-ring

Cap

Double 0-ring

HV-IF022A 4>5,17 HV-IF028A> HV-IFOOIB,

PT IN06IB,~I10514>19 Yes

X-78

X-7C

X-7D

Hain steam

Hain steam

Hain steam

~ C HV-IF022 B

C IW-IF022C

C IAf-IF022D

4,5,17

4,5,17

4,5,17

HV-IF028B> HV-IFOOIFPT-IN061F, PT-IN051F

HV-1E028C> HV-IFOOIKPT-IN061K> PT-IN051K

HV-IF028D> HV-IFOOIPPT-IN061P> PT-IN05IP

4>19

4>19

4,19I I

Yes

Yes

X-8

X-9A

Rev ., 4/81

Hain steam line drain

Feeduater

C HV-IF016

C IFOIOA

17> 18

14>18

HV-IF019

HV-IF032A> IN-IF013,HV-IF042, HV-1F104

19

14,19

SSES-FSAR

TABLE 6.2-22 ContinuedPa8c 6

Penetration Description

Inboard Isolation BarrierType Barrier Description/Test Valve No. Notes*

Outboard Isolation BarrierBarrier Description/

Valve No. Notes*

Exemptionto 10CFR50,Appendix JRequired

X-58A

X-58B

X-59h

X-59B

X-60A

X-60A

X-60A

X-60B

X-61A

X-61A

X-61A

X-61B

X-62A

X-62B

X-63A

X-63B

X-64A

X-64B

X-65A

X-65B

X-66A

X-66B

X-72A

X-728

Main steam,RWCU inst (4) A

Hain steam,RWCU inst (2) h

Reactor level inst

Reactor level inst

0 sample

0 sample

0 sample

Reactor Water Sample

Demin. Water

Flow Instrumentation

A

h

C SY-15740B

C SV-15776B

C SV-15750B

C IN-IF019

C 1-41-018

h

Main steam inst (2)

Main steam inst (2)

Main stcam inst (2)

Hain steam inst (2)

Hain stcam,RWCU inst (3)

Hain steam inst (2)

Prcssure inst (3)

Reactor level inst

Reactor level inst

Reactor level inst

Reactor level inst

Liquid radwaste

Liquid radwaate

h

h.

h

A

A

h

h

C liV-16116hl

C UV-16108A1

ILRT Leak Veriiication C 1-57-193

10

10

10

10

18

l8

18

17>18

18

10

18

10

10

10

10

10

10

10

10

10

10

10

17, 18

17, 18

SV-15742B

SV-15774B

SV-15752B

UV-1F020

1-41-017

1-57-195

HV-161 16A2

UV-16108A2

10,11

10,11

10,11

10 >11

11 >19

11>19

11,19

19

19

19

10 ~ 11

10,11

10>11

10>11

10, 11

10,11

10,11

10,11

10,11

10>11

10>11

11,19

11,19

Rev. 22, 4/81

SSES-FSAR

TABLE 6.2-23

IVITIAL A'.ED BOUN DAHY CONDITIONS FOR IV ADVERT ENTSPR A Y ACTUAT ION STIJDY

-00Tz.m e Zero

toDrvwell

Volume (™t~)Pressure (PSI A)Tem pera t ure (F)Relative Humidity (n)Spray Rate (GPN/ TRANS)

Met well

23960014.81501000/0

23960034. 8325910010700/1

Volume — Vapor Region (Ft ~)Suppression Pool (Ft~)

P ressure (PSI A

Temperature (F)Relative Humidity (K)Suppression Pool Free Surface Area (Ft~)

>letwegl-to-Drvwell Vacuum Breake. "-

Number of Valve AssembliesFlow Area Per Assembly (F t~)Flow CoefficientAssumed Vacuum Breaker Lifting P ressure

RHR System — Drgwell Spray Mode

Service Mater Flow Hate (GPM)Ser vice Mater Temperature (F)Heat Exchange Effectiveness

14859013155014.8501005277

(puid)

14590013155030. 28501005277

of 52.050.353

9000320. 245

Rev. 22, 4/81

SSES-FSAR

6.3.5 INSTRUMENTATION RE UIREMENTS

Design details including redundancy and logic of the ECCSinstrumentation are discussed in Section 7.3.

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

The HPCI, CS, and LPCI are automatically initiated on low reactorwater level or high drywell pressure. (See Table 6.3-2 forspecific initiation levels for each system.) The ADS isautomatically actuated by sensed variables for reactor vessel lowwater level and',drywell high pressure plus the indication that atleast one LPCI pump or both CS pumps in the same loop areoperating. The HPCI, CS and LPCI automatically return fromsystem flow test modes to the emergency core cooling mode ofoperation following receipt of an automatic initiation signal.The CS and LPCI system injection into the RPV begin when reactorpressure decreases to system discharge shutoff pressure.

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

6.3.6 NPSH MARGIN AND VORTEX FORMATION AFTER A PASSIVE FAILUREIN A WATER TIGHT ECCS PUMP ROOM

NPSH calculations for ECCS pumps have shown adequate margin toassure capability of proper pump operation after a pool leveldrop due to a worst case passive failure in an ECCS water tightpump room. This capability will be verified duringpreoperational testing assuming a passive failure in the ECCSpump room resulting in the lowest pool level with subsequentoperation of the ECCS pump with the smallest NPSH margin aboveNPSH required. ECCS pump data is presented in Figures 6.3-75thru 6.3"78.

The pool level drop has been determined assuming a passivefailure in a ECCS water tight pump room with operator action 10minutes after an alarm in the room indicating high water level.This lowest suppression pool water level will also be used duringpreoperational testing to verify the absence of vortex formationin the flow approaching the suction strainers in the pool duringECCS pump operation. Pump performance and pump noise will bemonitored during these tests to determine if pumps are sensitiveto suction flow conditions in the suppression pool.

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 ESSWpumphouse are divisionally separated. Two bays provide physicaland 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 pumphouseventilation system are powered from Class 1E 125 V dc and 120 Vac systems. These electrical systems are discussed in Chapter 8.

The ESSW pumphouse unit heaters support the ventilation system asdiscussed 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 requiredfor safety are as follows:

a) All electric unit heaters, see Subsection 9.4.8

b) Instrumentation for monitoring airflow from the ESSWpumphouse ventilation system

c) Instrumentation for alarming in the main control roomof high-high and low-low temperatures in the ESSWpumphouse

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 toSubsection 9.4.2.2.

Rev. 22, 4/81 7.3-101

SSES-FSAR

one group will not interfere with proper operation of theredundant 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 coolinginstrumentation and control system is discussed in Section7.3.2.6.4.1.9 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 asfurther defined in IEEE 379 (1972), "Application of the SingleFailure Criterion to Nuclear Power Generating Station ProtectionSystem," 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 isdemonstrated in the Section on Conformance to IEEE 279 (1971)paragraph 4.6 and IEEE 308 (1974). See Sections 7.3.2a.5.3.1.6and 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 safetyanalyses 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 designedand qualified to withstand all anticipated environmental conditions inaccordance with IEEE-323-1974 and IEEE-344-1975.

7.6.1b.1.2 Primary Containment and Suppression PoolTemperature Monitoring System

7.6.1b.1.2.1 System Identification

The Suppression Pool systems are designed to monitor the temperature in theprimary containment and suppression pool during normal plant operations andafter LOCA.

7.6.1b.1.2.2 Safety Evaluation

The indication of containment temperatures in the control room is requiredfor post accident monitoring and is safety related. The initiating contactsfor the automatic start of the drywell fans are derived from electronicswitches in the temperature sensing loop. This function is safety related.The system design conforms to all applicable criteria for physical separationand divisionalization. Refer to Subsection 7.3.l.lb. The hardcopy timeplotof the containment temperatures is operating history only and is not safetyrelated. However, redundant systems are provided.

iOThe indication of suppression pool temperature in the control room is requiredto ensure that the plant is always operating within the technical specificationlimits. Manual, operator action is required to maintain the plant within thespecifications. Suppression pool temperature is also required for postaccident monitoring. Both of these functions are safety related.

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

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

The primary Containment and suppression chamber temperature elements andtemperature 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 powersources. Division I Class IE bus (120 V ac) powers Loop A, Division IIClass IE bus (120 V ac) powers Loop B.

Four dual element RTDs per redundant system are located in the primarycontainment 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 definethe area of the heat source within the primary containment.

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

Two redundant indicators, for the primary containment are located in the maincontrol room. The initiating contacts for the high speed start of thedrywell cooling fans (refer to system description in Section 9.4) and derivedfrom the two redundant temperature sensing elements located in the servicearea of the fans. If high temperature is detected the electronic switcheswill initiate the high speed start of the drywell cooling fans.

Electronic signal converters with full electrical input-output isolation areplaced between safety related instrumentation and the input channels to therecorders.

!Two redundant multipoint recorders for the primary containment temperaturemonitoring system provide a permanent history of all RTD measurements to theoperator in the control room.

Each temperature sensing circuit is equipped with alarm switches and initiateone 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 remoteshutdown panel. Refer to Subsection 7.4.1.4 for system description. Instrumentranges 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, eachof which performs as described below.

Eight RTD's per redundant system are located in the suppression pool approximatelysix inches below the minimum pool water level. These sensors are locatedaround the pool in order to provide a good spatial distribution of pooltemperature. 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 inthe control room. This electronic unit converts the RTD signals into degreesFahrenheit and computes the average of the eight temperatures. If one ofthe RTDs fails, an error alarm is generated, and the failed RTD may be removedfrom the calculation of the average by operator action. The average valueis displayed by digital indicators located both on the electronic unit and onthe main control board. A keyboard allows the operator to display anyindividual temperature input.

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

A digital printer located on the electronic unit periodically prints theaverage temperature, plus the individual temperatures, plus the current dateand 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 interfacewith other plant information systems. The electronic unit has a self checkingdiagnostic system that provides an error alarm if a failure is detected inany part of the system.

In addition to the eight temperature sensors mentioned above, there are fouradditional sensors associated with Division I. These sensors are located inthe suppression pool, sixteen feet below minimum water level. They are usedfor display only and are not used in the calculation of average temperatureand 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 andsuppression pool temperature monitorinq system

7~6; 1b -1 .2. 6- - Se D a ra tion-J

Physical and electrical separation is provided for the safetyrelated iastrumentatioa. Nonsafety circuits are isolated byelectronic converters vith .full input-output .isolation.

7,6 Pb,-1 2~7—genatiooaZ.. Consideration-

The system is designed to function during normal plant operationand after a DBA.

7 6 11.-1.2 8- -Zn~ironmental -Consideration-

All temperature seasing elements located inside the containmentare desiqned. to operate. in the normal operating environment,durinq and after a LOCA. All electronic eguipment and indicatingdevices are located within the control structure.. Expectedenvironmenta1 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 monitoringis desiqned to provide indicatioa and a record in the controlroom of the suppression pool'level durinq normal plant operationand 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

36030'8o

100o30'02o

141o30'43o

179o

180

30'16o30'18o

268o30'70o

318o

319030'48

30'50o

Radius

34'-6"34 I 6 II

44'4'4

I 6ll

34'-6"

44'4'4'-6"

34 I 6ll

44'4'4

I 6ll

34 I 6ll

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 systemswhose functions are not essential for the safety of the plant andpermits an understanding of the way the reactor and importantsubsystems are controlled. The systems include:

(1) Reactor vessel — instrumentation VLSSS

(2) Reactor manual control system — instrumentation andcontrols, NSSS

(3) Recirculation flow control system — instrumentation andcontrols NSSS

{0) Reactor feedwater system — instrumentation and controlsNSSS

(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 probeNSSS

(9) Reactor water cleanup system — instrumentation andcontrols NSSS

(10) Refueling interlocks system

(ll) Nuclear Pressure Relief System — instrumentation 5controls

(12) Rod block monitor system(13) Loose parts monitoring system

7.7.~~ . Reacgog Vessel - Instrumentation

those syste

Rev. 22, 4/81 7& 7 1

Figures 5.1-3a and 5.1-3b show the instrument numbers,arrangements of the sensors, and sensing equipment used tomonitor the reactor vessel conditions. Because the reactorvessel sensors used for safety systems, engineered safeguards,and control systems are described and evaluated in other portionsof this document, only the sensors that are not required for

ms are described in this subsection.

SSES-FSAR

7.7.1.11.1.5 Testability 0The rod block monitor channels are tested and calibrated with procedures givenin the applicable instruction manuals. The RBMs are functionally tested byintroducing 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 timethe operator must evaluate conditions before manually changing to the nexthigher rod block set point line.

7.7.1.12 Loose Parts Monitorin~ System

The Loose Parts Monitoring System will monitor, alarm and record the ReactorVessel acoustics for the presence of internal loose parts in accordance withR.G.1.133 Draft-2 Rev. 1.

The system will monitor the points listed below. When an impact event signalexceeds a selectable amplitude, an alarm will occur and peak impact and impactrepetition will automatically be recorded and timed sequentially, for eachselected channel.

Eight piezoelectric accelerometers are attached externally to the ReactorVessel:

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

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

c. Two mounted approx. 180 apart and at 90 rotation from the upper vesselsensors mounted on or near the recirculation suction lines to monitor thevessel 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 onthe 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 andassociated circuitry, is designed to limit nuclear steam supply system pressureunder various modes of reactor operation.

7.7.1.12.2 Equipment Design

The Nuclear Pressure Relief System controls and instrumentation consist ofmanual control/pressure sensor channels each dedicated to its respectivesafety relief valve and associated valve operator (solenoid operated airpilot valve). The pilot valve controls the pneumatic pressure applied tothe air cylinder operator. Upon energizing the pilot valve, pneumatic pressureis directed from the accumulator to act on the air cylinder operator causing thesafety relief valve to open. Upon again de-energizing the pilot valve, airin the air cylinder is exhausted and the accumulator is once again isolatedvia the de-energized pilot valve. An accumulator, one for each valve, isincluded with the control equipment to store the pneumatic enexgy for safetyrelief valve operation. Safety relief valves are automatically initiated byhigh reactor pressure conditions. Cables from the pressure sensors forvessel pressure are routed

Rev. 22, 4/Sl 7.7-62a

SSES-FSAR

10"-FR50- Appendix A.

Criteria- 24-

The RBM provides an interlocking function in the control rodvithdraval portion of the "RD reactor manual control system.This design is separated from the protective functions in theplant to assure their independence.

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

En addition, the RBN has been designed to meet "appropriateprotection system criteria....acceptable to the RegulatoryStaff." (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 accordancewith 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 thenu"lear steam supply pressure relief function vithout jeopardy tothe saf ety-related A DS function, 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 forminimizing the probability of abnormal reactor coolant pressureboundary leakage.

(2) 10CPR50 Appendix A — "riterion 15.

The Nuclear Pressure Relief System is designed to afford adeguateadditional marqin to assure that the design conditions of the"eactor coolant pressure boundary are not exceeded during anycondition of normal operation, including anticipated operationaloccurrences.

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

The components of the Nucl ar Pressure Relief System aredesigned, selected, fabricated, erected and tested to thehighest, practical, current industrial standards. The System is

Rev. 22, 4/81 7.7-78

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. FINAL SAFETY'NALYS/S .RFsPOET

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SSES-"SAR

tone selector switch, area selector switch, message taperecorder, river warning speakers'and monitors, and an outdoorroof siren. This system supplements "he radiation monitoringsystems described in Chapter 12.

During emergen"y conditions the plant operator ac+ivates thesystem by selecting the designated ala m and area to be covered.The. alarms and instructions are broadcasted v'a he PA systempage lines to all speakers in selec+ed areas throughout tJ eplant. Durinc an emergency the night time mute function ofoutdoor speakers will be ove ridden. The r'er warning speakershave independent amplifiers with output monitor nc in the controlroom~

The operator switches the system to of, after confirmation ofnormal conditions. The preferred power for the EVAC system issupplied from Unit 1 vi..al ac bus, and the alterna+e power is fedfrom Unit 2 vital ac bus. During Unit 1 opera+ion while Unit 2is under construction, power to the EVAC system is fed from heUnit 1 computer UPS bus. The preferred power for the roof sirenis supplied from Unit 1 plant 125 V dc bus and the alternatepower is fed from Unit 2 plant 125 V dc bus. During Unit 1operation while Unit 2 is in construction stage, the alternatepower to the roof siren is fed from a separate 125 Vdc bus ofUnit 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 ofthe Security Communications System.

9.5 2.2.6 .Portable Communication System

Onsite portable radio communication systems are described in theSusquehanna SES Security Plan and in the Susquehanna SES Emergencyz a~.

9 5.2 .2.7 System Evaluation

System design considerations include diversity and operationalreliability. The in-Plant communication systems are providedwith reliable and redundant power supplies for uninterruptedcommunications between all areas of the Plant.

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

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SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND2

FINALSAFETY ANALYStS REPORT

REV. 22, O/S> .„ M-162 Sht,

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FIGURE 11.2-10

SSES-FSAR

13 5 PLANT PROCEDUR ES

13 5. 1 ADNINISTRATIVZ PROCEDURES

All safety-related operations at Susquehanna Steam ElectricStation Units 1 6 2 are conducted in accordance with detailed,written and approved procedures. Plant personnel receivetraining in the use of appropria te procedures and the proceduresare made available to them at all times.

13 5. 1. 1 Procedure Conformance

Procedure topics follow the guidance specified by applicableportions of Regulatory Guide 1 33, Revision 1 and procedures aroprepared 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 organizationsor contract organizatio'ns under the direction of the Supe visorof Operations, Supervisor of Maintenance, Technical Supervisor,Health Physics Supervisor, Quality Supervisor, Personnel andAdministrative Supervisor, and Security Supervisor. The plant

!procedure categories and a typical schedule for procedure preparationare shown on Figure 13.5-1- Review of safety-related proceduresuse and changes thereto, is performed by the Plant OperationsReview Committee (PORC} and approved by the Superintendent ofPlant as described. in Section 13. 4. In addition, functional'nitprocedures will be reviewed by Nuclear Quality Assurance.

Procedures are periodically reviewed to determine if changes arenecessary or desirable Applicable procedures are reviewed aftersignificant system or equipment modification, and following anunusual incident,"such as a hazardous condition, an unexpectedtransient, a significant operator error, or equipment malfunctionwhere the procedures contributed to the cause of the incident, orwere inadequate in mitigating the effects of the incident.When an operation is temporarily altered in such a manner thatportions of an existing procedure do not apply, then the existingprocedure may be temporarily changed. Temporary changes to

Rev. 22, 4/81 13 5-1

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PROCEDURES

ADMIHISTRATIVE

ALARM RESPONSE

CHEMISTRY

EMERGENCY

EMERGEHCY PLAH

ENVIRONMENTAL SURVEILLAHCE

FUEL NAHDLIHG

GEHERAL PLAHT

HEALTH PHYSICS

IHSTRUMEHTATIOH A CONTROL

MAINTENANCE

MATERIAL COHTROL

OFF-HORMAL

OPERATING

GUALITY

RADWASTE MAHAGEMEHT

REACTOR EHGINEERIHG

RECORDS

RELAY CALIBRATION

SECURITY

SPECIAL EVENTS

SURVEILLAHCE TEST

TRAIHIHG

MOHTNS PRIOR TO FUEL LOADING

34 32 30 28 26 24 22 20 18 16 14 12 10 8 6 4 2

CD

CD

SSES-FSAR

condition arise, the plant operating staff shall take whateveraction is necessary including, but not limited to, stopping thetest in order to restore safe plant conditions. During startuptesting, the plant operating staff is specifically responsiblefor compliance with operating technical specifications, andcompliance with the provisions of the operating license.

14.2 '.2 Test Prere uisites

Specific test prerequisites are identified in each preoperationaltest procedure. The test director verifies that eachprerequisite is completed and properly documented prior tosignoff in the official test copy of the procedure. If aprerequisite in a preoperational test cannot be satisfied, thetest director will list the prerequisite as a test exception tothe Preoperational Test.

As a prerequisite to preoperational testing, proper operation ofeach alarm loop is verified and listed in an appendix to thetest. During the preoperational test, system parameters arevaried and interlocks are tested which cause alarms to actuate.Those alarms which are actuated during the course of the testwill 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 togeneration of a test change notice form, the test dizector marks up theofficial test copy of the procedure and init:als/dates the change.

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

Test change notices for startup test procedures shall be initialed/dated byan on-shift licensed senior operator in addition to the test director. Reviewand approval for test change notices on startup test procedures is providedby the PORC.

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

a) Non«Intent Changes

iRev. 22, 4/81

For procedure modifications that do not changeacceptance criteria and do preserve the intent of thetest, the test change notice may be approved afterperformance of associated testing.

4

b) Intent Changes

For procedure modifications that alter the acceptancecriteria or the intent of the test, the test changenotice is approved before performance of associatedtesting.

14.2-12

SS ES-FS AR

information will be sorted and reported for a period of two yearsprior to fuel load on the first unit. The Manager-NuclearSupport 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 confirmedby trial-use during the Initial Test Program. Those procedures that do notrequire nuclear fuel are confirmed adequate to the extent practicable duringthe Preoperational Test Program. Those procedures that require nuclearfuel are confirmed adequate to the extent practicable during the StartupTest Program.

The plant operating staff is responsible for confirmation ofoperatinq and emergency procedures. The Superintendent of Plantis responsible for ensuring that comments/changes identifiedduring confirmation are incorporated in finalized procedures.

It is not intended that preoperational test procedures explicitlyincorporate or reference plant operating and emergencyprocedures. These tests are intended to stand on their own sincethey are not necessarily compatible with configurations andconditions required for confirmation of facility operating andemergency procedures. Startup test procedures will'ncorporateand reference plant operating and emergency procedures to theextent practical.

14-2-10 ~ INITIAL-FUEL- LOADING AND INITIAL CRITICALITY

Initial fuel loading is accomplished in accordance with startuptest procedure, ST-3 Fuel Loading Initial criticality isaccomplished in accordance with startup test procedure ST-4, PullCore Shutdown Margin. These procedures comply with the generalguidelines and regulatory positions contained in Regulatory Guide1.68 (Revision 1, January 1977). Test abstracts establishing theobjectives, prerequisites, test method, and acceptance criteriafor these procedures are presented in Subsection 14.2. 12.

14 2- 11 T>ST PROGRAM SCHEDULEcd

Rev. 22, 4/81 14. 2-19

The Preoperational Test Program is scheduled for 15 monthsduration on the Unit 1 and Common components and for 12 monthsduration on the remaining Unit 2 components..(See Figure 14.2-4a

~ '

SSES-FSAR

(P30.1) Control Structure HSV S stem Prep erational Test

Structure Hav System and its interlocks inside the control structurebuilding to demonstrate this system's ability to maintain a positivepressure above atmospheric during normal operation and highradiation signal when the emergency outside air supply mode isrunning. To demonstrate the ability of the Control Structure HGVto isolate before chlorine reaches the isolation dampers whenchlorine is detected in the outside air intake.

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

Test Method - The system operation is initiated manually and fanperformance, damper operations and heating element operation aredetermined. The differential pressures with respect to outsideatmosphere .are measured. Required controls are operated'orsimulated signals are applied to verify the emergency filteroperation on high radiation signal, automatic recirculation onhigh chlorine signal, system manual isolation and other systeminterlocks and alarms.

Acce tance Criteria - The system performance parameters are inaccordance 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 toControl Structure Heating/Ventilating Units and Control roomfloor 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, andInstrument Air System are available. Required electrical powersupply systems are available.

Test Method - The system is operated to demonstrate chilleroperation and chilled water pump performance. Required controlsare operated or simulated signals are applied to verify automaticalignment of the system under emergency conditions (start ofemergency condenser water recirculation pump) and other systeminterlocks and alarms.

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

SSES"FSAR

Test Method - The battery performance test is manually initiatedby connecting the battery bank to the Resistor I.oad Bank anddischarging the batteries at a constant current for a specifiedperiod of time.

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

Then the battery charger is connected to the batteries and thedistribution panels to verify that they can equalize charge thebatteries while simultaniously providing power to the normalplant loads. The battery charger is also connected to theResistor Ioad Bank and current is increased to its maximum ratingwith the charger isolated from its associated battery bank.

Alarms are simulator and verified to operate properly.

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

(P76.1) Plant Leak Detection S stem Prep erational Test

Test Ob'ective - 'To demonstrate the operability of the PlantIeak 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) orsimulated signals are applied to level sensors to verify the leak

'etection systemalarms'cce

tance Criteria - The system performance parameters are inaccordance 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 areain accordance with design requirements.

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

Test Method - The lighting system for the crane is energized andobserved for proper operation. The bridge and the trolley arespeed-tested in both directions. Current and voltage readingsare taken in both directions. The proximity switchesare tested for both the bridge and the trolley including trolleymovement restriction switches in zones A, B, and C.

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

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

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

(P100.1) Cold Functional Test

capable of operating on an integrated basis in normal andemergency modes, to demonstrate that adequate power supplies forthe class IE equipment will exist-

completed and plant systems are ready for operation on anintegrated basis.

Test Method - Emergency Core Cooling Systems (RHR 6 Core Spray)are lined up in their normal standby mode. The plant electricalsystem is lined up per normal electrical system lineup (For Unitl this lineup may be different than the lineup for two unitoperation). Loss of coolant accident signals are initiated withand 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 secondarycontainment:

(1) Show an appropriate plant elevation and section drawings,, those structures and areas that will be maintained atnegative pressure following a loss-of-coolant accident andthat were considered in the dose calculation model;

(2) Provide the Technical Specification limit for leakage whichmay 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 verifythat the systems provided are capable of reducing to andmaintaining a negative pressure of 0.25", e.g., within allsecondary containment volumes.

RESPONSE

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

2) See Technical Specification 3/4.6;.5.3 for the limiting conditionsfor operation and the surveillance requirements for the SGTS. Allleakage into the secondary containment is treated by the SGTS.Refer to subsection 6.2.3.2.3 for a discussion of containmentbypass leakage.

3) The Standby Gas Treatment System (See Subsection 6.5.1.1) inconjunction with the reactor building recirculation system(see Subsection 6.5.3.2) and the reactor buildig isolationsystem (see Subsection 9.4.2.1.3) is provided to produce andmaintain negative pressure within affected volumes of thesecondary containment. Actuation and operation of the abovesystems will be used to verify that the negative pressure isestablished and maintained.

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

Ventilation Zone I-Ventilation Zone II-

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

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 willbe such that in each affected ventilation zone the negativepressure will be maintained. The interconnecting ductwork of therecirculation system will equalize the negative pressurethroughout 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 TechnicalPosition "Steam Bypass for Mark II Containments," which isenclosed.

RESPONSE

A comparison of the Susquehanna SES design with your proposed BTP"Steam Bypass for MK II Coatainments" is presented below. Theitem 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 andcontrols supplied by GE meet the same ESF standards ofquality, redundancy and testability as the RHR system, ofwhich it is a part. The system is manually controlled andactuated.

The consequences of actuation of the wetwell spray on ECCSfunction 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 leakagefor small steam breaks as presented in Section 6.2.1 of theSusquehanna FSAR complies with the intent of the proposedbranch technical position; although it does not assume anormal plaat depressurization/shutdown time of 6 hours. Thecalculation assumes that the steam leakage is terminalted bysome operator actioa (containment sprays, ADS) within 15minutes after an abnormally high suppression chamberpressure is observed (830 psig). The maximum suppressionchamber pressure expected during a IOCA, assuming alldrywell air has been carried over and no steam leakage hasoccurred, is 25 psig. Significantly exceeding thispressure (to &30 psig) indicates a leakage situation andnecessitates operator action. Further, the calculationconservatively neglects any containment heat sinks (poolsurface, containment walls, etc.).

The method employed to calculate the maximum allowable steambypass lakage flow characteristic (A/rgb) has been previouslydescribed in some detail in submittals to NRC questions onthe Hatch l nuclear plaat. Briefly, it simply involves anend point type calculation of the mass of steam which can beadded to the suppression chamber above 30 psig to givedesign pressure (45 psig), conservatively assuming alldrywell 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 heatsinks/condensation. Knowing this mass of steam QM andassuming that the operator action will be delayed 10 minutesafter observin'g the 30 psig, and that the action willrequire 5 more minutes to take effect (5t = 15 min. total),the allowable lakeage rate m = Am/At can be calculated. Theflow characteristic A/~k can then be calculated from

M=A/ lvps chp"(

g

where bP is 'the pressure difference between the drywell andsuppression chamber at quasi-steady flow (equal P<g/g H,where H = vent submergence). The result is an A/~k = .0 6ft~ 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. SeeSubsection 6.2.1.1.3.2.

With respect to compliance with the proposed Branch TechnicalPosition "Steam Bypass of Mark II Containments," the followingSusquehanna SRP position statement is respectfully provided:

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

As documented in a letter of August 5, 1977 from G. G. Sherwoodto E. G. Case of the NRC, the SRPs constitute a substantialincrease in the information required just to describe the degreeof compliance of various systems. This increase in turnrepresents a substantial resource expenditure which isunjustified and which could cause proj ect delays if required ofthese projects. As stated in the, reference letter, General

Rev. 22, 4/Sl 021.10-2

SSES-FSAR

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

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

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 thisSummer and that Revision 2 which is now referenced is out-of-date, as it does not adequately reflect the status of currentpool dynamic loads. Discuss how the DAR will be updated to reflectthis status and discuss any other reports you intend to submitto document your plant design.

RESPONSE:

PPGL is working with the other Mark II owners to developmethodologies, analytical programs and test data which willprovide improved definitions of hydrodynamic loads. This efforthas resulted in Revision 3 to the DFFR, and is expected to resultin further revision to that report. lt is presently beingrevised to reflect the current position of the Mark XI owners.

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

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

Rev. 22, 4/81 021.21-1

SSES-PSAR

Identify all openings provided for gaining access to the secondarycontainment, and discuss the administr'ative controls that will beexercised over them. Discuss the instrumentation to be providedto monitor the status of the openings and whether or not the positionindicators and alarms will have readout and alarm capability in themain control room.

RESPONSE:

1) Secondary Containment Access Openings:

Door Nos. Elev. Col. Coordinates Security Monitored

101102103-0104-0119A120A571-0

670670670670676676818

U/29U/37.4U/20.6U/29P/20.6P/37.4P/32

YesYesYesYesYesYesYes

Roof Hatch 8 Elev. 872, coordinates: P/37.4 (Security Monitored)

2) Doors 5119A, 120A and 571-0 provide access into the secondarycontainment through the use of card reader/cipher keyboard control.Doors 101, 102, 108-0, 104-0 and the roof hatch (54001) will notnormally be used to gain access into the secondary containment.All transactions will be logged into the Security Data andManagement System (SDMS). All alarms generated will annunciateat both the Security Control Center (SCC) and Alternate SecurityControl Center (ASCC). The plant control room will not have areadout or alarm capability. Both the SCC and ASCC are, however,manned continuously 24 hours a day.

Instrumentation to control and monitor the status of secondarycontainment is described in Chapter 7.0 of the Susquehanna SESPhysical Security Plan.

Rev. 22, 4/81 021.31-1

SSES-FSAR

Subsection 4.2.2.2 of the DAR states that, the chugging loads onsubmerged structures and imparted on the downcomers will beevaluated later. .Provide the present status of these evaluationsand the schedule for your submission of the completed evaluation.

RESPONSE:

The calculation of submerged structure loads due to chugging willuse the improved chugging load methodology developed under Mark IZOwners Group Task A16. The appropriate design sources will be usedwith the Green's function solution for the SSES annular containmentto provide the pressure distribution in the suppression pool. Thepressure around a structure will be integrated to determine the netpressure load on the structure. A description of this methodologyand verification will be included in the DAR. The chugging sourcesused will be developed from the pressure time histories provided byKWU for the design assessment (see SSES DAR, Section 9.5.3).

The downcomer has been assessed for the chugging loads and theresults will be incorporated into the DAR. The other submergedstructures 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 regardingloads resulting from pool swell waves following the pool swellprocess or seismic slosh. Discuss the analytical model andassumptions used to perform these analyses.

RESPONSE:

The analytical method of calculating the loads resulting fromseismic slosh and the assumption used are described in awriteup to be included in the OAR. This information will besubmitted 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, downcomerstiffners, downcomer diameter, etc.)

RESPONSE:

A complete description of the GKM-IIM test program, test results andevaluation of the test data is provided in Chapter 9.0 of theSusquehanna SES DAR. The GKM-IIM tests were structured to be asprototypical of the Susquehanna SES plant configurations as waspractical. As such, concerns related to FSI, downcomers stiffnessgdowncomer diameter, etc., are fully addressed.

Rev. 22, 4/Sl 021.75"1

SSES-FSAR

Provide the time history of plantof responses of plant structures,components to pool dynamic loads.modifications resulting from pool

specific loads and assessmentpiping, equipment andIdentify any significant plant

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 foundin SSES DAR, Section 4.1. In addition, the plant specific LOCA andchugging load definition developed from the GKM II-M test program canbe found in Subsection 9.5.3. This load definition will be used toevaluate the conservatism of the DFFR LOCA load definition developedfrom the GKM II-M test program can be found in Subsection 9.5.3. Thisload definition will be used to evaluate the conservatism of the DFFRLOCA load definition and is scheduled for submittal in Revision 5 ofthe 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 timehistory loads.

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

Summary of the results of piping analysis will be provided in theDAR 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 recombinerSupport 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 chamberwalls and diaphragm slab.

f) Diaphragm slab reinforcements changed from'5 to 90 toincrease 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 andsuppression pool temperature versus time for the followingevents:

(1) A stuck-open SRV during power operation assuming reactorscram at 10 minutes after pool temperature reaches 110 F andall RHR systems operable;

(2) Same as event (1) above except that only one RHR trainavailable;

(3) A stuck-open SRV during hot standby condition assuming 120 Fpool temperature initially and only one RHR train available;

(4) The Automatic Depressurization System (ADS) activatedfollowing a small line break assuming an initial pooltemperature of 120 F and only one RHR train available; and

(5) The primary system is isolated and depressurizing at a rateof 100 F per hour with an initial pool temperature of 120 Fand only one RHR train available.

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

RESPONSE:

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

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SSES-FSAR

With regard to the pool temperature limit, provide the followingadditional information:

(1) Definition of the "local" and "bulk" pool temperature andtheir application to the actual containment and to thescaled test facilities, if any; and

(2) The data base that support any assumed difference betweenthe local and the bulk temperatures.

RESPONSE:

The terms "Local" and "bulk" temperature are used as defined inSubsection III.C.l.a of NUREG 0487, "Mack II Containment Lead PlantProgram Load Evaluation and Acceptance Critera", United States NuclearRegulatory Commission, October 1978.

Because of the design features of quenchers and their orientation in thesuppression pool (as discussed in the SSES DAR, Subsection 8.5.5),the differences between "local" and "bulk" pool tempoeratures areexpected to be small. Therefore, the difference should not exceed thevalue which was previously derived for ramshead discharge devicesin Mark I plants (10'). It is intended to verify the numbers usingdata from in-plant tests which are presently under preparation forLaSalle and Zimmer.

Rev. 22, 4/81 021.78-1

SSES-FSAR

uestion 021.79:

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

(1) Type, number and location of timperature instrumentation that will beinstalled in the pool; and

(2) Discussion and justification of the sampling or averagingtechnique that will be applied to arrive at a definitive pooltemperature.

RESPONSE:

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

o Number and Location of Tem erature Instruments: 20 remotetemperature detectors (see figure 021.74-35) in each suppressionpools

-16 remote temperature detectors located just below the min.water level and arranged to provide 2 each on 8 locations aroundthe 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 eachlocation in each division, except for 4 remote temperaturedetectors 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, pooltemperature is conservative due to the placement of the 16 pooltemperature detectors. These 16 detectors are evenly distributed nearthe 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 previouslylisted in Table 7.2-4. This table has been intentionally leftblank. Please clarify this discrepancy.

RESPONSE:

Table 7.2-4 was deleted because the information thereon has beenincorporated in the plant Technical Specifications. Someinformation from Table 7.2-1 and all the information from Tables7.2-5 and 7.2-6 has been deleted from Section 7.2 and is alsocontained in the Technical Specifications as the appropriatesingle point of reference for this data. Various discussions inSection 7.2 have been revised by appropriately referencing theTechnical Specifications rather than the deleted tables.

Rev. 22, 4/81 032.52"1

SSES-FSAR

Discussion of the Emergency Core Cooling Systems and theassociated tables are incomplete and inconsistent. Correct andclarify the following:

1) The same instruments are used for Reactor Vessel low waterlevel and Primary Containment high pressure for many ESFsystems. The specification shown for these instruments inTables 7.3-1 through 7.3-5 are not consistant. Correct tripsettings, ranges, and accuracies shown for theseinstruments.

2) These tables have allotted columns for instrument responsetimes and margins (of trip setting) to meet requirements ofIEEE 279-1971 Section 3, but most data has been omitted.Response times should indicate minimum and/or maximum whereapplicable.

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

4) Figure 7.3-5 has several errors:

o It does not show two ADS logics as indicated in7.3.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 CSrequired to initiate ADS as indicated in7.3.l.la.l.4.4.

5) Table 7.3-2 indicates only one reactor water levelsetpoint (-149 inches) for the ADS. Section7.3.1.1a.l.4.4 indicates two level setpoints, a low anda lower water level.

6) Use of level swtiches with a range of -150"/0/+60" toinitiate ADS and CS action with trip settings at -149 doesnot seem like conservative design. Justify the use of thisrange for this application. Discuss accuracy of the tripsetting and how it is affected by normal and accidentenvironmental 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 thisinstrument in Table 7.3-4 is 10-240 psig only.

8) Section 7.3.1.1a.l.4.5 on ADS Bypasses and Interlocksindicates that it is possible for the operator to manuallydelay 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 for105 seconds." Table 7.3-2, Figure 7.3-8 Sht. 3 and Table6.3-2 all indicate a time delay of 120 seconds. How is atime delay of 105 seconds achieved?

9) Explain why two ranges (50-1000 psig and 50-1200 psig) arelisted for the Reactor Vessel Low Pressure instrument inTable 7.3-3.

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

Table 7.3-9 HPCI System Minimum Numbers of Trip ChannelsRequired for Functional Performance does not agree withTable 7.3-1 HPCI Instrument Specifications. Table 7.3-8does not list HPCI pump high suction pressure or TurbineOverspeed as shown in Table 7.3-1. Table 7.3-8 lists twoitems, HPCI pump flow and HPCI pump discharge flow, notshown in Table 7.3-1.

12) Table 7.3-4 Low Pressure Coolant Injection - InstrumentSpecifications does not agree with Table 7.3-10 Low PressureCoolant Injection System Minimum Number of Trip ChannelsRequired for Functional Performance. Table 7.3-10 does notlist Reactor low pressure or Pump discharge pressure asshown in Table 7.3-4. Table 7.3-10 lists several tripchannels which are not shown in Table 7.3-4. These includeReactor vessel low water level inside shroud, Reactor vessellow flow, Primary containment high pressure, and Reactorvessel low water level (Recirculation Pumps).

13) Table 7.3-11 Core Spray System Minimum Numbers of TripChannels 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 allappropriate instrument functions and the number of channelsprovided. The trip settings and response time informationhas been deleted, and is provided in the TechnicalSpecifications. Tables 7.3-8 thru 7.3-11 are deleted, withappropriate number of channel information incorporated intoTables 7.3-1 thru 7.3-4. Revisions to Table 7 '-5 have beensubmitted 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 therequirements of IEEE 279-1971, Section 3.

3. The HPCI turbine overspeed trip is awhich is integral with the turbine.discussion of the HPCI turbine. Theand accuracy information is providedSpecifications.

mechanical device,See Section 6.3, foroverspeed trip settingin the Technical

4, Figure 7.3-5 is revised to show a simplified picture of theADS and LPCI/CS initiation logic. The" ADS division I and IILogics, discussed in revised Subsection 7.3.l.la.l 4-4 andshown in detail by Figure 7.3-8 sheet 3, are identical andenergizing either will initiate ADS. Therefore they areshown twice in Figure 7.3-5. Relating the simplifiedpicture 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 inDiv. II) and the right to logic C in Division I (or D inDiv. II). A note has been added,to Figure 7.3-5 to clarifythe separate logics for Div. I and Div. II. The referenceto 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 andRHR) 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 eachfrom the reactor water level Ll, and reactor water level L3.Both signals are required before ADS is automaticallyinitiated. The set point for this action is provided in theTechnical Specifications.

6. The instrument trip settings have been removed from thetables of Chapter 7 and included in the TechnicalSpecifications'he level switch trip setting of -149inches for ADS and CS will be changed and will be within theproper accuracy and range of the instrument. The tripsetting accuracy related to abnormal operating temperaturewithin the drywell is discussed in the response to question032.59. Instrument drift is included in developing theinstrument set points.

7.

/

8.

The LPCI pump discharge pressure permissive for the ADS hastwo 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.

The ADS timer setpoint found in Table 6.3-2 is an upperlimit. The correct setpoints (including margin) areprovided in the Technical Specification. The proper timedelay time is by mechanical adjustment of pneumaticallyoperated 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 actualnumerical value. The 105 second time value is nominal, andwas used to allow for the margin and tolerance of thedevice. The proper value is provided in the TechnicalSpecification.

9. The two trip systems for CS have diverse instrumentsspecified for reactor vessel and the same instruments areused in LPCI low pressure. Tables 7.3-3 and 7.3-4, asrevised, give the instrument ranges for both trip systems.The trip setting values are provided in the TechnicalSpecifications.

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

11. Table 7.3-1 has been revised to include HPCI pump minimumflow bypass and the HPCI pump flow controller signaling theHPCI turbine. The turbine overspeed trip is a mechanicaldevice that is integral with the turbine, see Section 6.3.The turbine overspeed instrument range has been added toTable 7.3-1. The number of channels provided is added toTable 7.3-1, and Table 7.3-8 is deleted. The minimum numberof trip channels required have been added to the TechnicalSpecifications.

12. The LPCI Table 7.3-4 has been expanded to include theinstruments of the actual design and the number of channelsprovided. The margin and trip setting of Table 7.3-4 aswell as Table 7.3-10 have been deleted.

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

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SSES-FSAR

UESTION 040.2

The staff requires that the following qualification test programinformation 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 extremeparameters, both maximum and minimum values, expected tooccur during plant shutdown, normal operation, abnormaloperation, and any design basis event.

(c) Time required to fulfillits safety function whensubjected to any of the extremes of the environmentalenvelope 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 describethe above items.

(9) The information requested above shall be provided for atleast one item in each of the following groups of Class 1Eequipment.

(a) Switchgear

(b) Motor control centers,

(c) Valve operators (in containment)

(d) Motors

(e) Iogic equipment

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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 CFR50, the staff requires a statement verifying: (a) that allClass 1E equipment has been qualified to the programdescribed above, and (b) that the qualification informationis available for an NRC audit.

RESPONSE:

The qualification test program information for ClasslE equipment is provided in the Susquehanna SES Environmental(}ualification Report For Class lE Equipment submitted underseparate cover.

Rev. 22, 4/81 040.2-2

SSES-PS AB

start on the autostart signal and operate on standby forfive minutes.

(d) Verifying that on loss of offsite power in conjunctionwith a safety features actuation signal the dieselgenerators start on the autostart signal, the emergencybuses are energized with permanently connected loads,the auto-connected emergency (accident) loads areenergized through the load sequence, and the systemoperates foz five minutes while the generators areloaded with the emergency loads.

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

(4) The voltage levels at the safety-related buses should beoptimized for the full load and minimum load conditions thatare expected throughout the anticipated range of voltagevariations of the offsite powez source by appropriateadjustment of the voltage tap settings of the interveningtransformers. Me require that the adequacy of the design inthis regard be vezified by actual measurement and bycorrelation of measured values with analysis results.Provide a description of the method for making thisverification; before initial reactor power operation, providethe documentation required to establish that thisverification has been accomplished.

RESPONSE

I. Refer to Figures 8.3-1, 8 3-2, 8.3-3 and 8.3-15 for the followingdiscussion on undervoltage detection and transfer logic.The primary bus transfer on loss of offsite power isinitiated at the 13.8 kV startup switchgear. Each class 1E4.16 kV switchgear buses provide the backup undervoltagetransfer. Refer to Subsection 8.3 for discussion on busarrangement and the interconnection of the offsite powersupplies 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 offsitepower supply and the capability of connecting to thesecond offsite power supply by the closing of the l3.8kV tie breaker (breaker 52-10502) .

The undervoltage detection system at each 13.8 kVswitchgear bus consists of (1) incoming feeder (offsitepower supply) undervoltage -clays — device 27AI, (2) busundervoltage relay — device 27A2, and (3) tie busundervoltage relay - device 27A1.

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

Device 27AI is an instantaneous plunger type relaywith pickup setting at 93.6 volts (78% of the rate120 volts). Two independent single phase relaysare used to monitor the A-B and 0-C phase voltages.The incoming breaker is tripped on coincidencelogic of the two undervoltage relays at 91 7 voltswith 30 cycle time delay.

(b) Device 27A1-Provides the permissive for closing oftie breaker

Device 27A1 is a long time induction disc typeundervoltage relay set at 82 volts (68% of rated)and time dial 1/2. Two single phase relay areprovided for monitoring the availability of thealternate offsite power supply at the 13. 8 kV leveland provide a coincidence logic for the closing ofthe tie breaker

(c) Device 27A2 — initiates the bus transfer)

Device 27A2 is a 3 phase instantaneous plunger typerelay with three full wave bridge rectifiers. Therelay is set to drop out at 30 volt (25% of rated).Bus transfer is completed by the closing of the tiebreaker (permissive by device 27A1).

2. Each 4.16 kV class 1E switchgear bus is provided with apreferred and an alternate (offsite) power supply andone diesel generator feeder as discussed in Subsection8 3.1.3

The undervoltage detection and backup bus transfer onloss of offsite power or sustained degraded voltage on the busis provided by (1) incoming feeder undervoltage relay-device 27',(2) bus undervoltage relay - device 27A, and (3) degraded voltageprotection relays-devices 27B1, 27B2, 27B3, and 27B4. The devicesettings for the Class IE bus undervoltage protection are summarizedin the following Table 40.6-1.

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

SSES-FSAR

Device 27AI — provides the permissive for closing of the incomingbreaker

Device 27AI is a single phase induction disc type relay set at 92volts and time dial 1/2. This relay is used to monitor theavailability of'the offsite power supply at the class lE 4.16 ivlevel.

(b) Device 27A — initiates the bus transfer

Device 27 A is a 3 phase instantaneous plunger type relay withthree full wave rectifiers. The relayis set to drop out at 18 volt or 15% of rated bus voltage. The4.16 kV bus transfer is initiated with a time delay of 10 cyclesby tripping of the prefer incoming feeder breaker. The transferis completed if the alternate offsite power supply to this 4.16 kVbus is available (permissive by device 27AI). In case the alternateoffsite power is not available, the standby diesel generator isinitiated to start with a 0.5 second delay.

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

The additional level voltage protection for each 4.16 kV Class IEbus is provided to assure that voltage levels at all Class IEdistribution buses meet the minimum requirement of all safetyrelated equipment.

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

If a degraded voltage condition occurs on the 4.16 kV Class IEbus, with no LOCA signal present (see Figure 8.3-15), which is below thesetting of relays 27B1 and 27B2, an alarm (coincidence logic) will beinitiated after 10 seconds. The same relays will initiate the bus transferafter 30 minutes LOCA signals will bypass relays 27B1 and 27B2 orbus transfer will be blocked by LOCA. The 10 second time delayis provided to preclude spurious alarms. The 30~inutes timedelay 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.

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SSES-FSAR

In addition, relays 27B3 and 27B4 will initiate an alarm andbus transfer after 17 seconds when the bus voltage is degradedbelow the setting coincident with an LOCA condition. These tworelays are also connected in a coincident logic with time delayrelays to preclude spurious tripping of the offsite power sources.This protective scheme will force a loss of offsite power on the4.16 kV Class IE bus on degraded bus voltage.

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

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

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

Tripping of the offsite pover supply at the 13.8 kVlevel is accomplished by a coincidence logic of tvoindependent'ingle phase undervoltage relays. Thebackup tripping of the same offsite power supply to theClass 1E 4 16 kV svitchgear is provided by a 3 phasefull wave rectifiers type undezvoltage relay forminimizing nuisance tripping such as loss of a-..singlecontrol fuse in the detection circuit.. The total timedelay allowed by restarting {starting) of class lEequipment after a DBA is 13 seconds as shown on'able8.3-1. 10 seconds is reserved for diesel generatorstarting. Therefore, 3 seconds is allocated for voltagesensing and bus transfer. Pze-operating tests villverify that the time delay on the bus transfer does notexceed the allowable time.

As discussed in (I) of above, offsite power supply zsautomatically disconnected at the 13.8 kV level. If thetransfer is not completed within the time delay of theClass 1E 4 16 kV bus transfer circuit, the offsite powersupply is also disconnected at the 4.16 kV level. Theundervoltage detection sensors and circuits are designedin accordance with IEEE std 279-1971

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4)4(

(2) All loads on each 4.16 kV Class 1E switchgear bus exceptthe 480 volt load center ceder are shed on loss ofpower to the bus. Once the bus is re-energized, the4.16 kV Class lE loads are loaded in accordance with thepre-set time delay. Load shedding and reloading of 4.16kV class lE loads are repeated as discussed abovewhenever the bus becomes de-energized.

(4)

Refer to Chapter 16 for Technical Specification.

Transformer tap settings ace selected for optionaloperating voltage levels for a11 loading conditionsunder the anticipated voltage variation of the offsitepower supplies. The continuous operating voltage ateach level is maintained within + 10% o rated. Pre-ope ational tests verify the actual voltage levels.

III. Relay Settings:

The function and settings of undervoltage relays are determined in consideration

of the full load, minimum load, and the largest motor starting conditions

that are expected throughout the anticipated range of voltage variations

for the offsite power sources.

The following design criteria are used:

(1) The maximum allowable voltage at no load or the minimum load condztxons

is 110% of the motor rated voltage.

(2) The minimum voltage under the maximum running load condition xs 90/

of the bus rated voltage.

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

See Table 40.6-1.

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SSES-FSAR

TABLE 40.6-1

SETTING TABLE (4KV BUS)

Device No.

27AI(preferred)

Function

Permissive to close thepreferred power incomingBreaker.

Alarm

Yes

Voltage~net tin

95%

Time~nettin

8 sec.

27AI(alternate)

Permissive to close thealternate power incomingBreaker

Yes 95% 8 sec.

27A

59/27

Initiate bus transfer.Trip the incoming closed breaker.

Bus over/under voltage(alarm only & located in loadcenter)

Yes

Yes

15%

110%/90%

10 cycles

10 sec.

27Bl27B2

Undervoltage alarm andinitiate bus transfer withtime delay relays.

Yes 95% 10 sec.

27B1X27B2X

Time delay relays with27B1 & 27B2 to initiatebus transfer.

No 30 min.

27B327B4

Initiate bus transferon LOCA condition

No 93% 17 sec.

Rev. 22, 4/81

SSES-FSAR

QUESTION 040.32:

In section 9.5.2.2 you describe the plant communications systemprovided. 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 areawhere fixed communications systems cannot be used, we require (asa minimum) that portable communications equipment be provided atstrategic work stations in the plant for use by personnel undersuch conditions.

RESPONSE:

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

Rev. 22, 4/81 040.32-1

SSES-FSAR

UESTION 40.95

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

a. Differentiate between equipment required to achieve and maintainhot shutdown and equipment required to achieve and maintain coldshutdown.

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) Describethe cable routing (by fire area) 'from source to termination, and

(2) Identify each fire area location where the cables areseparated by less than a wall having a three-hour fire ratingfrom cables for any redundant shutdown system, and

e. List any problem areas identified by item l.d.(2) above that willbe 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 wasconsidered. However, a more efficient and less time-consuming but equallyeffective method of review based on examination of each fire zone waschosen.

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), andthat manual operation and control post-fire were acceptable. See Table40.95-1.

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

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

Rev. 22, 4/81 40.95-1

SSES-FSAR

Group II consists of those systems required for hot shutdown. Several systemsare listed t;ogether because of the interdependency of these systems, e.g.diesel generators and auxiliaries. Again, these systems are further dividedinto Divisions I and II. All equipment and cables essential for Group II,Division I, must be single-fire isolated from all essential cables forGroup II Division II systems. Hence, as an example, RCIC (Division I) andHPCI (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-divisonalcircuit. This is necessary for diverse containment isolation function.If the system, say HPCI, is Division II, the cross-division isolationvalve circuits would be routed in their own separated conduits. Likewise,the RCIC system, Division I, the cross-divisional circuits would be routedin their own conduits. The cross divisional circuits of these two systems,will be single-fire isolated from each other and from both Divisions I andII up to the breaker.

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

The specific method of cable review is described below.

The Fire Protection Review Report analysis (Section 4.0) verifies that fireswill be contained within the zone of origin. Each fire zone is reviewedindividually. First, a raceway layout drawing is marked to show thedivisionalization of the safety-related raceway. The minority division isidentified and its raceway is listed. The term "minority division" refersto the electrical division which has fewer of its raceways routed throughthe fire zone in question. Actually, either division could be chosen forfurther examination, but the minority division represents the least effort.The cables in all the listed minority raceways are checked, and any notconnected to a safe shutdown system as given in Table 40.95-1 or to any ofthe components listed in Table 40.95-2 are deleted. All cable left isreviewed for its support of the system's safe shutdown function(s) and forthe effects of failure caused by fire. This step leaves safe shutdowncabling that violates fire zone separation.

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

*Single-fire isolated means either in separate fire zones or having thefollowing fire-protection measures:

a) Fire/smoke detection is provided in all fire zones containing essentialminority 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 onlyMain Steam Isolation Valves (manual closure functions only)Suppression Pool Temperature McnitorinqReactor Pressure Vessel InstrumentationGROUP II — Systems Required for Hot Shutdown

Division IRCICADSESHESSW Pumphouse HVACDiesel Generators and AuxiliariesDiesel Generator HVACContainment Instrument Gas

Division IlHPCIplus all Division II of these systems under Mode II, Divisionexcept RCIC.

GROUp III — Systems Required for Cold Shutdown

Division IRHRRHRSMESQESSM Pumphouse HVACDiesel Generators and AuxiliariesDiesel Generator HVAC

Division IIAll Division II of above

Rev. 22, 4/Sl

SSES-FSAR

2. Provide a table that lists Class 1E and Non-Class IE cablesthat are associated with the essential safe shutdown systemsidentified 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 thanRegulatory Guide 1.75 guidelines, cables for equipment whosespurious operation will adversely affect shutdown systems,etc.))

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

c. Identify each location where the associated cables areseparated by less than a wall having a three-hour fire ratingfrom cables required for or associated with any redundantshutdown 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 thenon-Class IE equipment from causing unacceptable influencesin the Class IE system.

b. The affiliated circuits are subjected to the samerequirements as Class IE circuits. Refer to Sections3.12.3.4 and 8.3.1.11.4 and Table 8.3-10 for cable routingrequirements.

c. The affiliated cables are routed with their respective ClassIE cables as described in Table 8.3-10. Therefore, theseparation between the affiliated cables and the redundantClass IE cables, including those cables required for safeshutdown, is in accordance with Regulatory Guide 1.75. The .

response to Question 40.95 addresses the cable separationbetween redundant shutdown systems.

Rev. 22, 4/81 40.96-1

SSES-FSAR

UESTION

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

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

b. Identify each circuit requiring a solution inaccordance with section III.G.3 of Appendix R, or

Identify each circuit meeting the requirements ofsection 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 shutdownsystem in two ways:

Affiliated circuit routed with shutdown circuit or insame enclosure:

A~nal aie: An open circuit of affiliated cable will notaffect shutdown system because the Class IE cable andaffiliated cable have the same qualified cableinsulation. (see Table 9.5-1).

For shorting or grounding of affiliated circuits, referto Section 8.1.6.ln paragraph 5) for the basis andmethods for separation/isolation of Non-Class IE andClass IE circuits.

The worst credible event which could affect one of theredundant shutdown trains through the affiliatedcircuit is a fire involving a raceway containing bothaffiliated cable and its associated shutdown systemcables. Assume in the worst case where these cablesare all shorted together with 120 V ac, 125 V dc, 250 Vdc, or 480 V ac cable due to a fire. (4 kV and highervoltage cables are routed in their own conduit).

The protective device(s) of the faulted circuits shouldbe tripped to prevent further damage into the shutdownsystem. If the Class lE protective device does nottrip, the shutdown equipment may be damaged, andtherefore prevent the equipment from performing itsshutdown function. However, failure of a Class lEdevice to trip must be considered a single failure,which is beyond the fire protection design basis. Inorder for this shutdown train, as designed, to fail dueto fire, these multiple, independent, low probabilityevents must happen simultaneously. This is consideredextremely unlikely.

Rev. 22, 4/81 40.97-1 „

SSES-PSAR

(2) Affiliated circuit sharing the same power supply of theassociated shutdown circuits:

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

b. Rc. The affiliated circuits are subjected to the samerequirements as Class IE circuits. The response toquestion 40.95 addresses this condition.

Rev. 22, 4/81 40.97-2

SSES-FSAR

5 ~ The residual heat removal system is generally a low pressuresystem that interfaces with the high pressure primary coolantsystem. To preclude a LOCA through this interface, werequire compliance with the recommendations of BranchTechnical Position RSB 5-1. Thus, this interface most likelyconsists of two redundant and independent motor operatedvalves with diverse interlocks in accordance with BranchTechnical Position ICSB 3. These two motor operated valvesand their associated cable may be subject to a single firehazard. It is our concern that this single fire could causethe two valves to open resulting in a fire-initiated IOCAthrough the subject high-low pressure system interface. Toassure that this interface and other high-low pressureinterfaces are adequately protected from the effects of asingle fire, we require the following information:

a ~ Identify each high-low pressure interface that usesredundant electrically controlled devices (such as twoseries motor operated valves) to isolate or precluderupture of any primary coolant boundary.

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

C. Identify each location where the identified cables areseparated by less than a wall having a three-hour firerating from cables for the redundant device.

d. For the areas identified in item c above (if any),provide the bases and justification as to theacceptability of the existing design or any proposedmodifications.

RESPONSE:

We have reviewed the major reactor pressure boundary highpressure/low pressure interface valves per Branch TechnicalPosition RSB 5-1. Using these criteria, check valves in serieswith motor operated valves (MOVs) are acceptable. A fire couldopen only the MOV. Many occurrences of this combination of checkand MOV exist at SSES in the Core Spray, Feedwater, and ResidualHeat Removal Systems, among others. Usually associated with thecheck valve is a pneumatic operator. This operator is fortesting purposes only and can neither unseat nor prevent fromseating the valve flapper when a differential pressure existsacross the valve. Hence, a fire-caused failure of the solenoidactuators for the pneumatic operators on these check valvescannot cause the valves to open inadvertently and thus cannotdegrade 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 (sixpairs total), all associated with the RHR System as high/lowpressure interface valves, consist of two remotely operatedvalves in series. One pair of these valves per unit in theshutdown cooling suction line. The other pair are in the linesto 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-11 - 2F052A'team Condensing Mode (air operated)

PV"E-11 - 2F051B/PV-E-ll - 2F052B Steam Condensing Mode (air operated)

The shutdown cooling suction valves are in separate divisions andare subject to the normal separation criteria. Also, the inboardvalve is located inside the inerted containment where a fire cannot be postulated. A cable-by-cable separation review wasconducted; cables from both valves are not routed in any singlefire zone other than the main control room and the RemoteShutdown Panels (RSP).

A reactor pressure vessel interlock prevents a shutdown coolingvalve switch in the main control room from opening its valvewhenever the vessel pressure exceeds the design rating of thedownstream RER piping. A design change is underway to relocatethe pressure interlock contact between the MCR and the RSP. Therelay panels containing the pressure contacts are located inseparated relay rooms. Hence, a fire or an operator mistake ineither the MCR or RSP will not cause an overpressurization.

The steam condensing mode valves are interconnected by design forcoordinated steam admission and pressure control and hence arenot separated nor divisionalized. Should both valves be drivenopen by fire, adequate overpressurization protection exists viaPSV-Ell"F055A 8 B to prevent rupture of the downstream RHRpiping.

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 yourpreservice and initial 20 month inservice testing program forpumps and valves. Enclosure 110-3 provides a suggested formatfor this submittal and a discussion of information we require tojustify any relief requests.

RESPONSE:

The preservice and initial 20 month inservice testing program forpumps 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 electricaland mechanical equipment under seismic and hydrodynamic loadingswill be performed by our Seismic Qualification Review Team (SQRT).A site visit at some future date will be necessary to inspect andotherwise evaluate selected equipment after our review of thefollowing requested information. The SQRT effort will beprimarily focused on two subjects. The first is the adequacyof the original single-axis, single-frequency tests or analysesof equipment qualified per the criteria of ZEEE Std. 344-1971.

The second subject is the qualification of equipment for thecombined seismic and hydrodynamic vibratory loadings. Thefrequency of this vibration may exceed 33 hertz and negate theoriginal 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 sothat SQRT can perform its review.

Several of the BNR Hark ZI OL applicants have stated in theirClosure Reports that equipment will be qualified for the SRSScombination of the hydrodynamic and seismic required responsespectra (RRS) . Similarly, when qualified by analysis, the peakdynamic responses of the equipment to the hydrodynamic and seismicloads will be combined by SRSS. The combining by SRSS of eitherthe RRS or peak dynamic responses for hydrodynamic and seismicloadings is not acceptable at this time.

To aid the staff in its review, provide a compilation of therequired response spectra listed below for each floor of theseismic 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 SRQTsubmittals 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 3components be in accordance with the =evise'ules in 10 CEH Pdr50, 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 minimuminformation is necessary ror our review:

(1) A preservice inspection plan to consis- of the applicableASllE Code Edition and the exceptions to the Coderequirements.

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

The preservice inspection plan will be revi..wed to support thesafety evaluation report finding on compliance with preserviceand inservice inspection requirements. The basis for thedetermination will be compliance with:

(1) The Edition of Section XI of the ASl}E Code stated in yourPSAR or later Edit'ons of Section XI =eferenced in theFEDERAL REGISTER that you may elect to apply.All augmented examinations established by the Commissionwhen added assurance of structural reliability was deemednecessary. Examples of augmented examination requirementscan be found in NRC positions on (a) high energy fluidsystems in SRP Section 3.2, (b) turbine disk integrity inSRP Section 10.2.3, and (c) feedwater inlet nozzle innerradii.

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

The inservice inspection plan should be submitted for reviewwithin six months of anticipated commercial operation todemonstrate compliance with 10 CFR Part 50, Section 50.55a,paragraph (g) . This plan will be evaluated in a safetyevaluation report supplement. The objective is to incorporateinto the inservice inspection program Section XI requirements ineffect six months prior to commercial operation and any augmented

Rev. 22, 4/81 121.8-1

examination requirements established by the Commission. Yourresponse should define all examination requirements that youdetermine are not practical within the limitations of design',geometry, and materials of construction of the components.

Attached are detailed guidelines for the preparation and contentof the inspection programs and relief requests to be submittedfor staff review.

RESPONSE:

The inspection program for Class 1, 2 and 3 components has beenprovided (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, systemsand components are to be designed for appropriate load combinations arisingfrom accidents and severe natural phenomena. With regard to the vibratoryloads attributed to the feedback of hydrodynamic loads from the pressuresuppression pool of the containment, the staff requires that safety-relatedmechanical, electrical, instrumentation and control equipment be designedand qualified to withstand effects of hydrodynamic vibratory loadsassociated with either safety relief valve (SRV) discharge of LOCA blowdowninto the pressure suppression containment combined with the effects ofdynamic loads arising from earthquakes.

The criteria to be used by the staff to determine the acceptability of yourequipment qualification program for seismic and dynamic loads are IEEE Std.344-1975 as supplemented by Regulatory Guides 1.100 and 1.92, and StandardReview Plan Sections 3.9.2 and 3.10. State the extent to which theequipment in your plant meets these requirements and the above requirementsto combine seismic and hydrodynamic vibratory loads. For equipment thatdoes not meet these requirements provide justification for the use of othercriteria.

RESPONSE:

I. BOP

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

The criteria for the qualification of BOP equipment for seismic loadsis described in Section 3.7b.3 of the FSAR. The criteria for loadcombinations and methodology for the design assessment andqualification of Safety related BOP equipment for seismic andhydrodynamic loads have been described in Sections 5 ' and 7.1.7 ofthe Design Assessment Report (DAR) Rev. 2. Basically the requirementsof IEEE Std. 344-1975 as Supplemented by Regulatory guides 1.100 and1.92 and SRP Sections 3.9.2 and 3.10 are covered in the criteria withthe following exception for spatial combination of three components ofdynamic motion as stated in Section 7.1.7.1.3 of the DAR. Thecriteria 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 thelarger value of the responses due to one of the horizontal dynamicloads by the absolute sum method."

All Susquehanna BOP equipment is being qualified for the criteriadiscussed above.

II. NSSS

LOAD COMBINATIONS:

These were transmitted to the NRC on 8/28/80 as Page 3 of Attachment Nto 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 AdequacyEvaluation Program which combines dynamic loads by SSES as accepted bythe NRC in NUREG-0484.

The individual items associated with the load combinations are addedas 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 arecombined by Absolute Sum, Double Sum, or Grouping.

Details for each item of equipment are contained in that equipment'sDesign 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 andone for BOP supplied equipment). These lists should includeall safety related mechanical components, electrical, instrumen-tation, and control equipment, including valve actuators andother appurtenances of active pumps and valves. In the lists,the following information should be specified for each itemof equipment.

(1) Method of qualification used:

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

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

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

(2) Indicate whether the equipment has met the qualificationrequirements.

(3) Indicate the system in which the equipment is locatedand 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 installedat the plant site?)

Rev. 22, 4/81 123.2-1

SSES-FSAR

(ii) An acceptable scenario of how to maintain hot stand-by and coldshutdown 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 allapplicable vibratory loads (individual and combined if required)for each floor of the nuclear station under consideration.

RESPONSE:

The response to this question was submitted via PLA-627 (Curtis toYoungblood) 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-plantequipment requiring reevaluation and specify why reevaluation is necessary(i.e. because the original qualification used the single frequency, singleaxis methodology, because equipment is affected by hydrodynamic loads, orbecause both of the above conditions were present) for each item ofequipment.

RESPONSE:

Originally almost all Safety related BOP equipments for Susquehanna hadbeen qualified for only Seismic loads. This equipment has been re-.evaluated dueto 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. Thequalification program for the BOP Safety related equipment is beingexecuted in the following four phases.

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

q rem pecxfx.ed xn FSAR Subsectx.on 3.7b.3.

Phase»II: Evaluation for Combined Seismic andH drod amic (SRV 8 LOCA) Loads:

The only known dynamic load at the time of execution of this phase of theprogram was Seismic loads. During this phase, the vendors supplying theequipment were required to qualify the equipment in accordance with there ui ents s

This phase was undertaken to evaluate if the existing Seismic qualificationof all Safety related BOP equipment could be extended to the combinedSeismic and hydrodynamic loads. The criteria used for the re-evaluation isdescribed in DAR Section 7.1.7. The general problem areas identifiedduring this evaluation and the proposed action to mitigate these problemsare shown below.

Rev. 22, 4/81123.3-1

SSES-FSAR

PROBLEM ACTION

Additional HydrodynamicLoads

Flexibility of EquipmentSupport not considered

o Retest and/or Reanalysis.o Modifications to equipment

or their Supports if required.

o Provide response spectreconsidering support flexi-bility.

Inadequate Modelling

Inadequate Testing

o Include Support Conditionsduring analysis or testing.

o Correct during reanalysis.

o Retesto Qualification by analysis.

Phase III: Re uglification Efforts:

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

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

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

The following are NSSS equipment:

SYSTEM

Safety Relief ValveMSIVFlow ElementRecirc. Pump MotorGate ValveHCUCRD ValvesSLC Storage TankSLC AccumulatorSLC PumpSLC Explosive Valve

MPL ij

B21F013B21F022/F028B21N051/52/53/54B31C001B31F023/31/32C12D001C12F009/10/ll/12C41A001C41A003C41C001C41F004

Rev. 22, 4/81 123.3-2

RHR Heat ExchangerRHR PumpFlow Orifice AssemblyLPCS Pump 6 MotorFlow Orifice AssemblyMSIV HeaterMSIV BlowerHPCI PumpHPCI TurbineFlow Orifice AssemblyRCIC PumpRCIC TurbineFlow Orifice AssemblyFuel Prep MachineGen. Purpose GrappleDryer S Separator SlingHead Strong BackControl Rod GrappleRefueling PlatformIn Vessel RackDef. Fuel Storage Cont.Fuel Storage Vault

SSES-FSAR

CONTROL ROOM PANELS

E11B001E11C002E11N012/N014E21C001E21N002E32B001E32C001/C002E41C001E41C002E41N007E51C001E51C002E51N001E18E001F18E011F19E008F19E009F20E002E21E003F22E006F22E009F22E012

Reactor Core Cooling BBPower Range Monitoring CabinetRPS Div. 1 and 2 Log VBRPS Div. 2 and 3 Logical VBNSSS Temperature Recorder VBFeedwater 8 Recirculation Instrument PanelNSSS Process Instrument PanelDiv 1 RHR/HPCI Relay VBDiv 2 RHR/HPCI Relay VBADS Ch A Relay VBMSIV Leakage Control Div 2 VBHPCI Relay VBRCIC Relay VBInboard Valve Relay BoardOutboard Valve Relay VBDiv 1 CS Relay VBDiv 2 CS Relay VBADS Ch B Relay VBMSIV Leakage Control Div 1 VBRadiation Monitoring Instrument Panel ARadiation Monitoring Instrument Panel BOperating BB

H12-P601H12-P608H12"P609H12-P611H12-P614H12-P612H12-P613H12-P617H12-P618H12-P628H12"P654H12-P620H12-P621H12"P622H12-P623H12-P626H12-P627H12-P631H12-P655H12-P606

H12"P633'12-P680

Rev. 22, 4/8l 123.3-3

SSES-FSAR

Termination CabinetsPlant Operation Benchboard

Condensing ChamberCondensing ChamberCondensing ChamberCondensing ChamberCondensing ChamberCondensing Chamber

NUCLEAR BOILER

LOCAL PANELS

H12-P700 SeriesH12-P853

B21-D002B21-D004ABB21-D006ADB21-D007ADB21"D008ADB21-D009AD

Reactor Water Clean-UpReactor Vessel Ievel and Pressure (A)Reactor Vessel Level and Pressure (B)Recirculation Pump AJet Pump BHigh Pressure Coolant Injection BReactor Core Isolation Cooling AResidual Heat Removal Channel AResidual Heat Removal Div. 2 Channel BRecirculation PumpsDrywell Pressure Local Panel ADrywell Pressure Local Panel BMain Steam Isolation Valve Ieakage ControlCore Spray Local Panel AStandby Liquid ControlMain Steam Flow A/BHigh Pressure Coolant Injection Leak Det.Core Spray Channel BMain Steam Flow C/DHigh Pressure Coolant InjectionReactor Core Isolation Cooling Leak Det.Main Steam Flow A/BMain Steam Flow C/DMain Steam Isolation Valve Leakage Con.High Pressure Coolant Injection Div. 1 AReactor Core Isolation Cooling Div. 2 BSRM/IRM

NUCLEAR BOILER

Temperature ElementTemperature ElementTemperature Element

H23-P002H23-P004H23"P005H23-P009H23-P010H23-P014H23-PoljH23-P018H23"P021H23-P022H23"P057H23-P058H23"P074 Div. 2H23-P001H23-P011H23-P015H23-P016H23"P019H23-P025H23-P036H23-F038 Div. 2 (B)H23-P041H23-P042H23-P073 Div. 1H23"P034H23-P037H23-P030/31/32/33

B21-N004B21"N010ADB21-N014AD

Rev. 22, 4/81 123.3-4

SSES-FSAR

Transmitter

Transmitter

TransmitterTransmitterTransmitter

Transmitter

Pressure SwitchTemperature ElementTemperature ElementVacuum SwitchTemperature ElementDifferential PressureTemperature ElementDifferential PressureLevel SwitchI,evel SwitchTemperature SwitchPressure TransmitterPressure IndicatorValve, Guide TubeMiscellaneous PartsPressure SwitchPressure SwitchLimit SwitchLimit SwitchI,evel TransmitterTemperature ElementDifferential PressureDifferential PressureDifferential PressurePressure SwitchSwitchPressure SwitchLevel SwitchLevel SwitchTemperature ElementTemperature ElementFlow Indicating SwitchDifferential PressureSwitchPressure SwitchFlow MeterLevel SwitchLevel SwitchLevel SwitchIevel SwitchIevel SwitchTemperature ElementTemperature ElementTemperature ElementTemperature IndicatorI,evel SwitchTemperature Element

B21"N015ADB21-N016ADB21-N017B21-N056ADB21-N064B31-N014CDB31-N023ABB31-N024ABC12-N013ADC12-N013EFC41-N003C41-N004C41"R003C51-J004AEC51-5110001C72-N003ADC72-N005ADC72-N006ADC72-N008ADEll-N008ABEll-N009ADEll"N013Ell-N015AEll-N015BEll-N018Ell-N021ABEll-N022ABEll-N023ABEll-N024Ell-N029ADEll-N030ADEll"N033ABE21-N003ABE21-N006ABE21-N007ABE32-N006E41-N002E41-N003E14-N014E41-N015ABE41"N018E41-N024ABE41-N025AHE41-N028ABE41-R002E51-N010E51-N011AB

thru E41-N030AB

Rev. 22, 4/81 123.3-5

SSES"FSAR

TemperatureTemperatureTemperatureTemperatureTemperatureTemperatureTemperatureTemperatureSwitch

ElementElementElementElement .

IndicatorElementElementElement

E51-N021ABE51-N022ABE51-N023ABE51-N025AD thru E51-N027ADE51-R005G33-N016AFG33-N022AFG33-N023AFG33-N044A

Rev. 22, 4/81 123.3-6

SSES"FSAR

QUESTION 123.4:

Describe the methods and criteria used to determine the acceptability ofthe original equipment qualification to meet the required response spectraof item 2. (iii). - 123.2 (iii).RESPONSE:

I. BOP

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

II. NSSS

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

Rev. 22, 4/81 123.4-1

SSES-FSAR

Describe the methods and criteria used to address the vibration fatiquecycle 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 ofequipment is not fatigue controlled since the number of cycles in anearthquake is low.

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

Fatigue effects in BOP equipment qualified by testing are accountedfor 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 (or1 faulted condition, i.e., SSE + SRV + LOCA) in each of front-to-back/vertical and side-to-side/vertical biaxial configurations. Inaddition, on some selected pieces of equipment, vibratory tabletesting is carried out for an extended duration of time (such as 30 to60 minutes) beyond the combined loading test. The input motions forthe extended duration tests will be such that the generated testresponse spectra for any segment of the extended duration tests willenvelope the SRV spectra. Furthermore, it will be ascertained thatthe equipment performs its intended function before, during and afterthe vibratory table tests. The results of the extended duration testswill be documented in the respective qualification reports.

II. NSSS

Vibration fatigue cycle effects for NSSS equipment designed to ASMEcode requirements was reviewed at GE by NRC consultants from BattellePacific Northwest Laboratories on October 7, 1980. The consultantsstated 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 maximumequipment response. These loads are controlling. GE testinggenerally consists of 5 upset and 1 faulted test of 30 seconds eachwhich is about 50$ greater than required to address strong motionvibration.

Rev. 22, 4/81 123.5-1

SSES-FSAR

Non ASME Code components qualified by analysis generally have not, inthe past, had to address vibration fatigue cycle effects. In mostcases, 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 theresults of the review of the original equipment qualification withidentification of (1) equipment which has failed to meet the requiredresponse spectra and required requalification, and (2) equipment which wasfound acceptable, together with the necessary information to justify theadequacy of the original qualificatioa.

RESPONSE

I. BOP

For cases where the original seismic reports can be extended toqualify an equipment for combined seismic and hydrodynamic loads byinspection and subsequent concurrence by vendor, such documents form apart of the qualification package. The following pieces of equipmentbought under the indicated purchase order (P.O.) fall into thiscategory:

(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 criteriadescribed in Section 7.1.7 of the Design Assessment Report. Thequalification reports for this equipment will provide the appropriatedocumentation.

II. NSSS

Refer to the Response to Question 123.3 for the list of equipmentreevaluated by GE oa the Susquehanna SQRT Program. All of theequipment listed in qualified to SQRT Criteria with the exception ofthe followiag:

B21"F022/F028B31-F031/F032

C12»F009/F010F011/F012

C41-A003C41-F004

E32-B001

MSIVGate Valve

CRD Valve

SLC AccumulatorSLC ExplosiveValveMSIV Heater

Data required from vendorOperability deflection analysisrequiredOperability deflection analysisrequiredA/E pipe accelerations requiredA/E pipe accelerations required

Test required

Rev. 22, 4/81 123.6-1

SSES-FSAR

E41-C002E51-C002F22-E006F22-E009

H12-P608

H23-P030"P031"P032-P033

163C1158

272A8005

272A8006

HPCI TurbineRCIC TurbineInvessel RackDef. Fuel StorageCont.Power RangeMonitoringCabinetSRM/IRM Panels

Flow Transmitteron H23-P074Switch on H12-P853Switch on H12-853

Test requiredAnalysis of lube oil piping requiredAnalysis requiredAnalysis required

Test required

Test required

Test required

Test required

Test required

Information to justify qualification of the equipment selected by theNRC for the Site Audit will be available at the site for NRCinspection. Information to justify qualification of the remainder ofthe 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 initem 6.(1) 123.6 (1) that requires requalification.

RESPONSE:

I. BOP

Typically, the qualification program is executed in the followingsteps.

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 shownin the attached Table 123.7-1.

II. NSSS

The response to Question 123.6 lists the equipment found by GE torequire requalification along with a statement defining the work to beperformed. All requalification will be completed on a schedulesufficient to permit NRC review prior to fuel load.

Rev. 22, 4/Sl 123.7-1

TABLE 123.7-1

SCHEDULE FOR COMPLETIONOF E UIPMENT REQUALIFICATION

Page 1 of 6

SQRTForm No.

E-109-1

E"109-2

E-112

E"117-1

E-118

E"119A"1

E-119A-2

E-119A-3

E-119BC

E-120-1

-120"2

E-121-1

E-121"2

E-135-1

E-135-2

E-136

E"151

E-152

E-155

J-038A

E~ni ment

4 kV Switchgear

4 kV Switchgear Sub-Components

ESW 8 RHR Pump Motors

480 V Safe-Guard Load Center UnitSubstations

480 V Motor Control Centers

Battery Monitors

Battery Fuse Boxese

Battery Chargers

24 Vdc, 125 Vdc S 250 VdcBattery Cells 6 Racks

125 Vdc Distribution Panels

24 Vdc Distribution Panels

125 V 6 250 Vdc Ioad Centers

250 Vdc Control Centers

Electrical Penetration(Medium Voltage)

Electrical Penetration(Low Voltage)

AC Instrument Transformers

Motor Generator Sets 8 ControlCabinet

Automatic Transfer Switches

Control Switches

Field MountedElectronic PressureTransmitters

No. of Items/2 Units

12

12

24

20

16

22

16

12

12

32

14

4 Sets

44

32

CompletionDate

3-13-81

5-15-81

Complete

3-27-81

4-17-81

3-27-81

3-27-81

3-27-81

5-29"81

3-20-81

4-10-81

3-27-81

4-10-81

5-15-81

5-15-81

3-27-81

Complete

Complete

6-15-81

Complete

Rev. 22, 4/81

SQRTForm No.

J-03B-1 thruJ-03B-14

E~ni ment

Panel — Mounted Instruments

No. of Items/2 Units

242

Page 2 of 6

CompletionDate

4th quarter 1981

J-05A-14,31,33,37, Control Panels 6 Devices10A 6 B, 43,47,49,92,93,95 6 97

31 5-30-81 (panels)6-15-81 (devices)

J-05B-1 Remote Shutdown Control Panel 5-30-81 (panels)6-15-81 (devices)

J-27

J-31

J-59-1 thruJ-59-10

Reactor Coolant Pressure BoundaryLeak Detection System

Annubar Flow Elements

RTD's 54

Complete (panels)6-15-81 (devices)

Complete

5"22-81

J-65-1 thruJ-65-4

Control Valves in Nuclear Service 28 3-27-81

J-65B-1 thruJ-65B-ll

Control Valves in Nuclear Service 86 3-27-81

J-69-1 6 2

J-69B-1 thru 6

J-70-1

J-70-2

J-92-1 thruJ"92-5

Pilot Solenoid Valves

Pilot Solenoid Valves

Pressure Regulating Valves

Process Solenoid Valves

Excess Flow Check Valves

74

76

238

5-15-81

5-15-81

5-15-81

5-15-81

5-1-81

J-98 Carrier Modulator(Isolator)

6"15-&1

M-ll

M"12

M"22-1 6 2

M-30 (78 forms)

M-30 (6 forms)

M-55

ESW Pumps

RHR Suction Water Pumps

Reactor Building Cranes

Diesel Generator

Diesel Generator

Reactor Vessel Top Head InsulationSupport Steel

4 Sets

4 Sets

Complete

Complete

4-3-81

Complete

2"27-81

Complete

Rev. 22, 4/81

SQRTForm No.

E -58

M-60

M-87-1

M-87-2

M-90

M-149

M"151

M-156

E~ni ment

Diesel Oil Transfer Pumps

Buried Diesel Generator Fuel OilStorage Tanks

Containment Hydrogen Recombiners

Hydrogen Recombiner Power Supply

Fuel Pool Skimmer Surge Tanks

Containment Vacuum Relief Valves

Suppression Pool Suction Strainers

Containment Nitrogen GasAccumulators

No. of Items/2 Units

20

32

60

Page 3 of 6

CompletionDate

Complete

3-27-81

5-15-81

Complete

4-27-81

5-22-81

Complete

Complete

M-159-1 thruM-159-21

Nuclear Safety 8 Relief Valves 58 5-1-81

M-160AC SRV Discharge Line 8, RHR ReliefValve F055 Discharge Line VacuumBreakers

68 5-15-81

M-164

-192

CRD Vent Valve Platform

High Density Spent Fuel PoolRacks

48 Modules

Complete

Complete

M"302

M-307-1 thruM-307-3

Expansion Tanks 6 Air Separators

Centrifugal Fans

Complete

3-13-81

M-308"1

M-308"2

Vane Axial Fans, Reactor Building

Vane Axial Fans, Diesel'eneratorBuilding

5-1"81

Complete

M-308-3 6 4

M-309-1 thruM»309-4

Vane Axial Fans, ESSW Pumphouse

Air Handling Units 12

Complete

4-17-81

M"310

M"315

M-317

'-320"1

Centrifugal Water Chillers

Reactor Building Unit Coolers

Drywell Unit Coolers

Chlorine Detectors

24

12

5-22-81

5-29-81

3"27-81

6-15-81

Rev. 22, 4/81

SQRTForm No.

M-320-2-1A 6 1B

M-320-2-2A

M-320-3

M-320-4

M-370-5A 6 5B

M-320-6-1A 6 1B

M"320-6-2A

M-320"6-3A 6 7

M-320-8

M-320-9

M-320-10

M-321"1

M-321-2

M"321-3

~Eni ment

Flow Switches

Flow Switches

Level Gauge

Pressure Differential Switches

Temperature Switches

Temperature Switches

Temperature Switches

Temperature Switches

Pressure Differential Transmitter

Temperature Detector Unit

Level Switches

Standby Gas Treatment System-Housing

Standby Gas Treatment System-Deluge Drain Valves

Standby Gas Treatment System—Control Panels

No. of Items/2 Units

28

24

10

18

4

Page 4 of 6

CompletionDate

6-15-81

6-15-81

6-15-81

6-15-81

6-15-81

6-15-81

6-15-81

6-15-81

6"15-81

6-15"81

6-15-81

2-20-81

5-1-81

3-6-81

M"323C-1

M-323C-2

M-325

M-327-1

M"327-2

M-334-1 thruZ-334-5

Air Flow Monitoring Unit

SGTS Exhaust Vent Flow Condition-ing 8 Sampling Probe System

High Efficiency Ventilation Filters

Chilled Water Pump

Cooling Water Pump

HVAC Control Panels 6 Devices 12

3"13-81

3-13-81

Complete

Complete

Complete

5-30-81 (panels)6-15-81 (devices)

M-336A

M-362

M"365

P"10A-1

HVAC Dampers

SGTS Centrifugal Fans

Chilled Water Relief Valves

Motor Operated Gate Valves, 6008

195 Units 5-8-81

Complete

5-1-81

6-15-81

Rev. 22, 4/81

SQRTForm No.

-10A"2

P-10A-3

E~ni ment

Motor Operated Gate Valves, 9008

Motor Operated Globe Valves, 90088 6008

No. of Items/2 Units

15

Page 5 of 6

CompletionDate

6-15-81

6-15-81

P-10B Motor Operated Stop Check Valves,9008

6-15-81

P-11A-1

P-11A-2

Motor Operated Gate Valves,900'ir

Operated Testable Check Valves,9008

6-15-81

6"1-81

P"12A-1

P12A-2

P12A-3

P-12A"4

Motor Operated Gate Valves, 150j/

Motor Operated Globe Valves, 300j/

Motor Operated Gate Valves, 300j/

Gear Operated Gate 8 Globe Valves,300 jj

24

20

6-15-81

6-15-81

6-15-81

6-1-81

P-12B-1

P-12B"2

-12B"3

Motor Operated GateValves, 150jj 6 3008

Air Operated Gate Valves, 150j/

Gear Operated Gate 8 Globe Valves,150 jj

14

13

6-15"81

6-1-81

6-1-81

P-14A

P-14B

P-15A

P15B-1

P-15B-2

P-16A-1

Motor Operated Globe Valves, 15008

Motor Operated Globe Valves, 1500//

Motor Operated Globe Valves, 15008

Motor Operated Gate Valves, 15008

Air Operated Gate Valves,1500'otor

Operated Butterfly Valves,150 jj

18

28

6-15"81

6-15-81

6-15-81

6-15-81

6-1-81

6-15-81

P16A-2

P-16A-3

Air Operated Butterfly Valves,1500

Gear Operated Butterfly Valves,150 jj

12

6-1-81

6-1-81

P"17A-1

-17A-2

Motor Operated Gate Valves, 900j/

Motor Operated Globe Valves, 9008

6-15-81

6"15-81

Rev. 22, 4/81

SQRTForm No.

P-17A-3

P"17A"4

P-17B

P-18A

P-31A

E~ni ment

Air Operated Testable CheckValves, 9008

Gear Operated Gate Valves, 900//

Air Operated Testable CheckValves, 90017

Gear Operated Gate Valves, 1508

Air Operated Butterfly Valves,1508

No. of items/2 Units

Page 6 of 6

CompletionDate

6-1"81

6-1-81

6-1-81

6-1-81

6-1-81

Rev. 22, 4/81

SSES-FSAR

UESTION 123.8

Describe plans for a confirmatory in-situ impedance test and an in-plantSRV test program or other alternatives to characterize the ability ofequipment to accommodate hydrodynamic loading.

RESPONSE:

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

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

Rev. 22, 4/81 123.8-1

SSES-FSAR

To confirm the extent to which the safety related equipment meets therequirements of General Design Criterion 2, the Seismic QualificationReview Team (SQRT) will conduct a plant site review. For selectedequipment, SQRT will review the combined required response spectra (RRS) orthe combined dynamic response, examine the equipment configuration andmounting, and then determine whether the test or analysis which has beenconducted demonstrates compliance with the RRS if the equipment wasqualified by test, or the acceptable analytical criteria if qualified byanalysis.

The staff requires that a "Qualification Summary of Equipment" as shown onthe attached pages be prepared for each selected piece of equipment andsubmitted to the staff two weeks prior to the plant site visit. Theapplicant should make available at the plant site for SQRT review all thepertinent documents and reports of the qualification for the selectedequipment. After the visit, the applicant should be prepared to submitcertain selected documents and reports for further staff review.

RESPONSE:

Susquehanna SQRT pre-visit information required forhas been submitted for all BOP and NSSS equipment.of Equipment" and the pertinent documents, reports,necessary information as required are available for

the SQRT site review"Qualification Summaryvendor prints and allSQRT review.

Rev. 22, 4/81 123.9-1

SSES-FSAR

The Susquehanna FSAR Section 3.7b.2.1 indicates that both a flexiblebase model and a fixed base model were utilized for the seismicanalysis of the containment building. Discuss and explain therationale for using two different models for the seismic analysis.Demonstrate the equivalency of the two models by comparing theirdynamic characteristics on the results from the two analyses.

RESPONSE:

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

A flexible base analysis, which takes into account soil structureinteraction effects, was used to generate structural responsespectra for evaluation of equipment, piping systems, etc. Seeattached Figures 130.20-15 through 130.20-18 for comparative responsespectra at the top of the reactor pedestal for both fixed andflexible base results.

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

The flexible base displacements are larger than the fixed basedisplacements by approximately 20-50%. This is shown in theattached Figures 130.20-11 through 130.20-14. These largerdisplacements for the flexible base analysis were used todetermine the required separation between the containment and thesurrounding 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 fortorsion...". 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, thereis torsion. The inertia force obtained from the dynamic analysis was usedby multiplying it with the eccentricity (the distance between the centerof mass and the center of rigidity) to obtain the torsional moment. Thismoment was then distributed to the structural walls for assessment.

A minimum excentricity of 5% was considered.

Rev. 22 4/81 130.21-1

.136—

~ 0.128-

Flexible Base Model Results

Fixed Base Model Results,

~228

I

~ 3

, 0.220

~caI o.2oo

I/9'5'

0.175

I

I ./8/0.154

I

i~/so0.137

l~/2I

j~/0 80.109

I.oeqI

10

11

~os'u

~>77/

I, 05212 0.046

I

22

(. ZS80.240

23

~8'830.614

.~sos0.446

I

I

j~345'0.294

I

j~2/g0.183

I

'~/360.128

I

I

1524I

~/9 7I

~/8

I

o.128 '7

./~/2

18 0.108

I

j~ot30.091

26

~078I

19 0.071I

I

I.o~tfI

IRev. 22, 4//81

UNITS: G's

13

.0320.021

~ a21 0,020

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINAL SAFETY ANALYSIS REPORT

CONTAINMENTHORIZONTALACCELERATIONS

OBE

FIGURE 130. 20-1

5

6

7

8

9

10

12

13

'~Z'M

l

0.251

I

~83/, 0.215

I

~zo30.189

I

j~gzo0.169

i

~/50.152 '

(~/48~

0.137

l~/36I

l 0.126

~/z5i~/o3

0.092I

jlloBo(, 0.067

I

I

~o520.034

22

14

.390.331

23

I

I

24

~Z7oJ

5

20716 P.l

t

17 0.161

~,/S4

5718 0.140

I

~/320.121

26 I

I~/2o19 0.100

I

~iot20 0.073

l

~//Z70,751

I

~55 40.545

I,

I~

I

(~4410.360

I

i~zBZ0.225

I

. (z+0.161

UNITS: G's

Rev. 22, 4/81

,d5 SUSQUEHANNA STEAM ELECTRIC STATION

21 0.034 UNITS 1 AND 2

FINAL SAFETY ANALYSIS REPORT

CONTAINMENTHORIZONTALACCELERATIONS

SSE

. 136 — Flexible Base Model Results

0.128 - Fixed Base Model Results .

F IGIIHE. 130. 20-2

.0400.059

I

~040> O.OS9

l

~03'P

I.'i O.O58

I

j~03S0.055

I

i~0360.051

I

,~0340.047

I

~o3z0.043

~O300.039

14

15

16

17

18

~ocr0.062

I

I

.o65~

0.061

I

I

~o~o0.057

QP

22

24

25

. /030.103

l

I

I~ioo0.101

.a%40.094

f

~os'.084

I

.a670.054

20.032

10

12

13

~ 27 28

.uz00.024

l

~0200,015 3p

I29 26

I

I 19

I

~os I0.012 2p

I

l~Oia

fo.oov

f

II 21

~o~o0.025 0.028

I ~ C

n

f

j~o4o0.035

l

~o0.026

I

l~o20.017

I

l.

j~o>

O.OI77

UNITS: G's

Rev. 22, 4/81

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINAL SAFETY ANALYSIS REPORT

o.136 — Flexible Base'odel Results

0.128 — Fixed Base Model Results

CONTAINMENTVERTICAL,ACCELERATIONS

OBE lF IGIJ RE 130. 20-3

9

~ 0 5 0 0.059

10

12

13

~ ops0.1 12

I

~O7 O0.111

'~is 50.162

I

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t

I

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4

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/

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I

16

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~oII80.070

~ os 80.082 17

[email protected]

.062

~ 057 0.045 0.046

. 005 0&

I

/~070.055

t

~os q0.04 1

I

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UNITS: Q'g

427 28

I

,CoOg0.050

I

~osv0.029 30

I4

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~oso0.01 2

4 29 26I

19

~os ~0.022 20

I

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I21

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IRev. 22, 4/81

SUSQUEHANNA STEAM ELECTRIC STATION

UNITS 1 AND 2

FINAL SAFETY ANALYSIS'EPORT

~

~~

~~I

136 —.Flexible Base Mode'1 Results

0.3.28 — Fixed Base Model Results

CONTAINMENT

VERTICALACCELERATIONS%RE

FIQURE ~ 130. 20-4

46 ~44

164 ~(97

260IM2~'

14

31

23

256 2g

102 ~104

~ 1,»0 l300423 gag 288 3t5

1,440 I&20

7,770

~IRIDO15

24

264 ~$ 1 g25

eee ~e'735

~

10

»

2,070 ~2'LQO

2,220 ~14)0

2,550 Q t I 0

2,720 ZERO

3,620 4000

3,830 'tZI0

16

17

18

26

19

24e~ek1$~

646~59

589 70'7

ss1 ~>ag

364 558

17

766 f99$ 4

UNITS: KIPS

12

4.010 ~44 l0

20

4O2 ~WOa

13

27

4,1 00~$ 55 Q

21

27

424 $35Rev. 22, 4/Sl

D.136 — Flexible Base Mo'del Results

0.128 — Fixed Base Model Results FIGURE 130.20"5

SUSQUEHANNA STEAM ELECTRIC STATION

UNITS 1 AND 2

FINALSAFETY ANALYSIS REPORT

CONTAINMENT

SHEAR FORCES

OBE

se ~4e

201 ~255

366 48 I

010 ~57331

126 1+0

14 23

1,380 I6 $ 0 010~654 ese ~4I l4

1.7so ~2l 3 0

2,180 Z 55 0

e,sso ~Z4l 50

15

16

17

440 ~41 93

404 f449

24

25

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014

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10

2850 3ggg

3.110 [335l 0

e,eeo ~380

18

26

011~85 l

.720 9 I 2.

'430

SZSQ

19

4,68o 5590

404 444

447 ~485

UNITS: KIPS

12 20

4,91o 5300 4ee ~549

13

'7

21

0,040~kola

27

see ~6O7Rev. 22, 4/81

II

*

..136 - Flexible Base Model Results

0.128 — Fixed Base Model ResultsFIGURE 130.20-6

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINAL SAFETY ANALYSIS REPORT

CONTAINMENT

SHEAR FORCESARE

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 ~

15 8.33 F. '7 424 2.42 P . a g

5 4o.s ~6.0

61,0 ~6l ~ 0 16 15.4 ~IS ~ /

25 16.8 ~III.Z

81.2 ~f/ 0 17 183 2I 3 17~ 108 //.

28.8 ~3'7. I

10

105 ~ll 5

124 ~/'37

145 I ~l149 tgy

18

26

173 ZD, 2

24.8 Z V. 5196 23,2

so1 ~2.22 19 16.6 ~242. 62

UNITS: 10'.F T

12 256 m3 20 14.9 l 7. 8

13 214 ~34lo 21 15.s ~l7. 5

27 222 ~@/ 2 27 18.0 /'7. I Rev. 22, 4/81

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINALSAFETY ANALYSIS REPORT

'0.136 — Flexible Base Model Results.

0 '28 — Fixed Base Model Results.

CONTAINMENTMOMENTS

OBE

FIGURE 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. s24 9.14'15 10.2 l2. I

s 4g,g ~6is. 3

sss ~RO. 6

ioo ~Ill

16

17

25

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20.5 ~24 6

S5.1 49. g

10.

iss ~i5 l

i52 ~f7

178 208183 QJ g

18

26

21.2 26 3

SOS 38 224.0 304 ] 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

~

~136 — Flexible Base Model Results

0.128 — Fixed Base Model Results

4~~53S 22 220 qg,+ Rev. 22, 4/81

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINALSAFETY ANALYSIS REPORT.

CONTAINMENTMOMENTS

s'c'C

FIGURE 130.20-8

2'2

sv ~4&

ieo ~~f2 I

14 23

131 J rO

10

ees~IZED>

'I

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sos ~eJRQ

s7s ~+72

ese ~Sg (

7'Z 7920

15

16

17

18

-26

so~@9

~oe t!0

4se~<7 l

491 503

396 Q'26

24

25

17

ee4 ~233

ees ~536

1,010 <>s ~$ 4.g

UNITS: KIPS

'2

13

1,070

30

71

20

21

4es ~$ 65Rev. 22, 4/81

1,090

136 — Flexible Base Model Results

0.128 — Fixed Base Model

Results'31

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINALSAFETY ANALYSIS REPORT

CONTAINEMNT

AXIALFORCES

OBE

FIGURE 130.20-9

6

I »~+'2126 Jg 67 77

256 ~24026 r5

23

2os ~Zan

15

0 ~

10

859 5 1 &

1oso ~15<

12so '~367

145o ~91

1590 lQ IG

~lS I 't1720

16

17

18

26

1o2 ~l<~

164 ~f41 I

719 gQ764 BOO

614 ~76 0

25

17

966 ~g(g

525 ~4465

UNITS: KIPS

12

1900

2010 f12'0

642 ~7i 'l l

662

~3544'

13 ~t70 l.2050

126

136 — Flexible Base Model Results

~

~

~

0.128' Fixed Base Model Results .

21

669

D5

Rev. 22, 4/81.

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINAL SAFETY ANALYSISREPORT

CONTAlNMENTAX(ALFORCES

SSE

FIGURE '30..20-10

136 - Flexible Base Model Results

~

~

0. 128 — Fixed Base Model Results

31.66

2

3

9 6127I

10

I tc,C.

'.81

30.0

i ~aSI 27.7

I ~3'I, 2I

i

I

j~~o,S21.4

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j )i~.~ l> 16.5

j~2.(. 014 4

I ~j3,8

14

15

16

17

18

26

19

t

~1 8.9

I

jCn3l

1 1.7

7.06

I

I~~,S I

UNITS: 10 FT

I

,~I4119

23

I

tI

S6I. S i Mi«'399

l83.5

I

,~so.a

r 53.94th32.4 ~

12

13

'.69

~4'.oe1.89

't. t8

20

21

3.54

I

I

'.10

Rev. 22, 4/81

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINALSAFETY ANALYSIS REPORT

CONTAINMENTHOB IZONTAL D ISP LACENIENTS

OBE

FIGURE 130. 20-1 1

D136 - Flexible Base Model Results

0.128 — Fixed Base Model Results

S 5I

38.6

36.6

i~vs. a

I 33.8

I~s.i.z

I

~s. i

~

29.6

I

iE~M26.1

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14

15

16

22

23

I

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24

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5

51.

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I

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I

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7

8

9

10

11

12

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,i 5.75

I

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~<.sv

17

I

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'+5'18 2 .1

26

j2< 8'4.3 UNITS: 10~ FT

19

20

~I% 1)

8.65

I

4.37I

I

3.'ti 1.3721

Rev. 22, 4/8iSUSQUEHANNA STEAM ELECTRIC STATION

UNITS 1 AND 2'INALSAFETY ANALYSIS REPORT,

CONTAINMENTHORIZONTALDISPLACEMENTS

SSE

FIGURE 130.20-12

15

16

17

d,649. 3410

12

13

~o.f 980.812

I

j~o,89 >2 ~ 0.804

I

I~o,as+3, 0,791 14

I

'~o,see4 0.752

. d.g2t5 . '.703

I

I

~o,7'926 0.648

.~0,7567 0.594

I

.d,7l 78 0.535 18

'~o.st@

~omit ~~

0.430 0.446 0.658

I

27 28 '9 26

j~o.5<770.329, 19

I I

l~u~z30 0.215 20

I

I~a.slh0.090 21

1.57

I

I

1.55

I

I

1.47I

~no1.41

I

~/.481.16

~ I

0.896

I

~d.974,

0.667

I

I aazs0.427

I

I g,+700.181

'2

23

24

25

17

~Z.W 72.69

I

I

1~2. i'22.64

I

I

1~21 (2.47

I

I

, ~2. 5'2.22

UNITS: 10 4FT

Rev. 22, 4/81

~d,Z95 '~0,%9S ~AZ'FS

.$ 36 - Flexible Base Model Results

0.128 — Fixed Base Model Results

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINAL SAFETY ANALYSIS REPORT

CONTAINMENTVERTICA'LD ISP LACEMENTS

OBE

P I G I I R E,130. 20-13

~ll .s~ s10

1.53

I

1.51I

I

j ~l.&O1.49

I

I

~r,ss1.41

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j~l. so1.32

14

15

l~l. 4'31..22 16

I

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j~i.so'IS'.00 l.J2

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22

I

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j~SDA p42.40

I

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2.23

3.oS2.19 17

~41.80

I

! ~i~1.39

5-5 1

4.18

I

.S.~ I

4.10

I

. ~~asI

3.44

/

ot.2.19

UNITS: 10 4FT

12

13

27 28f

29

;~o< j0.616 ~

I

I~O,RSL

30 0.364

jI

j~o.aa0.170

II

~5Kb 5,'5%>

26I

j~l. 7419 i 1.04

I

. ~I.'L'920 0.663

I

j~o.ass21

I0.282

O.S3o

Rev. 22, 4/81

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINAL SAFETY ANALYSIS REPORT

.136 — Flexible Base Model Results

0.128 — Fixed Base Model Results

CONTAINMENTVERTICALDISPLACEMENTS

SSE

FIGURE . 130.20-14

1.800

1.600

1.400

1.200zO

cc 1.000

.800

Pk~'hieWse

..600

.400

.200

.0000.1 '0.2 0.4 0.6 1.0 2.0 4.0 6.0 10.. 20.

FREQUENCY (HZ)

40. 60. 100.

LOCATION: RPV PEDESTAL

DIRECTION: HORIZONTALEARTHQUAKE: OBE

DAMPING: 0.005

Rev. 22, 4/Sl

I.SUSQUEHANNA STEAM ELECTRIC STATION

UNITS 1 AND 2

FINAL SAFETY ANALYSIS REPORT

RESPONSE SPECTRUMAT'RPV PEDESTALHORIZONTAL OBE

FIGURE 130. 20-15

0

/ 3.000

2.700

2.400

2.100

i.sooz0I-a 1.500

1.200

F(ex''ltlbd$ 8

900

600

~ 300

.0000.1 '.2 0.4 0.6 1.0 2.0 4.0 6.0 10.

FREQUENCY (HZ)

20. 40, 60. 100.

LOCATION: RPV PEDESTAL

DIRECTION: HORIZONTALEARTHQUAKE: SSE

DAMPING: 0.010

Rev. 22, 4/Sl

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS 1 AND 2

FINALSAFETY ANALYSIS REPORT

RESPONSE SPECTRUMAT RPV P ED ESTALHORIZONTALSSE

FIGURE 130; 20-16

kix'eel

hase

0.1 0.2 OA 06 10 2.0 4.0 6.0 10.

FREQUENCY (HZ)

20. 40. 60. 100.

. LOCATION.'PV PEDESTALDIRECTION: VERTICALEARTHQUAKE: OBEDAMPING: 0.005

Rev. 22, 4/B1SUSQUEHANNA STEAM ELECTRIC STATION

UNITS 1 AND 2FINALSAFETY ANALYSISREPORT

RESPONSE SPECTRUM AT RPVPEDESTAL VERTICAL OBE

FIGURE 130. 17

2.000

1.800

1.600

1.400

1.200

OI-cc 1.000

.800/legible

b~s e

r i~ Frxed!

~b~

t

~600

~400

~200

~ 0000.1 ~ 0.2 0.4 0.6 1.0 2.0 4.0 6,0 1 0.

FREQUENCY {HZ)

20. 40. 60. 100

LOCATION: RPV PEDESTALDIRECTION: VERTICALEARTHQUAKE: SSE

DAMPING: 0.010

Rev. 22, 4/81~ SUSQUEHANNA STEAM ELECTRIC STATION

UNITS 1 AND 2FINAL SAFETY ANALYSIS REPORT

RESPONSE SPECTRUMAT RPV PEDESTAL

VERTICALSSEh

F IQURE 130.'20-18

> I I I I I I I I I I I I I I I I I) I I I I Itttllll>llll.llllll'mI I I I I I < I I I f~ I I~s ~ ~ ~ ~ ~ ~ ~ ~ ~' FI ~ ~ ~ ~ ~ ~ ~ 0

. ~

~ '

I/L

I ~

I

MCNAB le/4r/v/t I

CA4i4ftt6/At ,c~L

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C5CCAVO lOeV4W/t t l ~

! o/kt I I i

/p )

~ .

~ f 4"

J '.C.

\ 1

t vRev. 22/ 4/81

SUSQUEHANNA STEAM ELECTRIC STATIONUNITS1 AND2

FINALSAFETY ANALYSISREPORT

FINAL PLANT GRADES

,7.FIGURE 2 ~ 5.—.24

SSES-FSAR

QUESTION 130.22:r

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

RESPONSE':

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

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

In the E-W direction (see seismic model on Figure 3.7b-9) the eccentricityis less than 5%. However, a miriimum eccentricity of 5% was considered byredistributing 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, itappears that the bracing is welded to the liner plate through theuse of an embedded plate without any anchorage to the containmentconcrete wall. Since the steel liner plate is not a structuralcomponent, indicate how the pulling forces from the bracing canbe resisted and how the leaktight integrity of the liner can bemaintained.

RESPONSE:

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

Rev. 22, 4/81 130.23-1

SSES-FSAR

It appears that portions of the recirculation pump seal coolingwater are not seismic Category I (Regulatory Guide 1.29). Thestaff requires additional information to show that a completeloss of pump seal cooling water would not lead to unacceptableconsequences.

RESPONSE:

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

General Electric's Licensing Topical Report, NED0-24083, RecirculationPump Shaft Seal Leakage Analysis, provides : an analytical basis forrecirculation pump seal leakage, assuming a failure of both coolingwater systems. This generic analysis predicts a bounding leakagerate well under 100 gpm. The generic analysis is applicable toSusquehanna. The report also documents test results, demonstratingthat pump seal integrity will be maintained if any one of the twocooling 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) 34of Appendix A to 10 CFR Part 50. The RHR by itself cannotaccomplish th cheat removal functions as required by GDC 34. Tocomply with the single failure criterion the FSAR describes analternate method of achieving cold shutdown in Section 15.2.9Insufficient information is provided to allow an adequateevaluation of this alternate method. In particular, we haverecently approved Revision 2 to SRP 5.4.7 (containinq BranchTechnical Position RSB 5-1) which delineates accceptable methodsfor meeting the single failure criterion. This Branch TechnicalPosition requires testinq to demonstrate the expected performanceof the alternate method for achievinq cold shutdown. You shoulddescribe plans to meet this requirement. In addition, we requirethat all components of the alternate system be safety grade(seismic Cateqory I) .

As a result of this requirement, the air supply to the automaticdepressurization system (ADS) valves, including the systemupstream of the accumulators, must be safety grade. This airsupply must be sufficient to account for air consumptionnecessary for valve operation plus air loss due to system leakageover a prolonged period with loss of offsite power.

RESPONSE.

As discussed in Subsection 9 3.1.5.1, the gas supply to the ADSvalues and the backup qas supply to the ADS accumulators issafety grade. Codes covering the design and construction ofthese compon'eats are discussed in Subsection 9.3.1.5.1All components that are a part of the alternate shutdown loop (seeSd>section 15.2.9 & Figs.15.2-14 and 15,2-15 are routinelytested as required by technical specifications. Testing of thetotal alternate shutdown system would not provide any additionalpertinent information and would result in introducing lowerquality (suppression pool) water into the vessel. Bsed on theabove, we do not feel that testing of the total loop is necessaryor desirable.This issue was tentatively resolved with the NRC on the Shorehamdocket (BWR/4) by an agreement to test one safety relief valve inSan Jose simulating the alternate shutdown condition. Therationale for acceptance of this plan was that the SRV is theonly component in the loop which has not been demonstrated to besuitable for alternate shutdown conditions. This test. wassuccessfully completed in December 1979.

Rev, 22 4/81 211 8-1

SS ES-PSAR

General Hlectric in conjunction vith the Three Mile Island OwnersGroup is planninq further SRV testinq in response to TMI relatedissues. This testinq. vill include conditions similar to thealternate shutdovn- conditions and will include a valve of CrosbyManufacture as is used in the Susquehanna plant. It is expectedthat these tests will further confirm that an in-plant test isnot required to demonstrate alternate shutdown conditionscapability.

REV 18, 1 $/80 211 8- 2

SSES-I'SAR

QUESTION 21 1 85:

Provide assurance that adequate NPSH exists for an ECCS passivefailure in a water- tight pump coom. Address the possibility ofvortex fo mation at the suction of the remaining ECCS pumps withthe lowered pool level. Discuss preoperational tests to beperformed to demonstrate that there is not impairment of ECCSfunction due to lowered suppression pool level.RESPONSE

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

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

Rev. 22, 4/81 211 85-1

SSES-FSAR

It is not evident that the assumed drop of 100 F in feedwater temperature0

gives a conservative result of this transient with manual recirculationflow control. For example, a feedwater temperature drop of about 150 Foccurred at one domestic BWR resulting from a single electrical componentfailure. The electrical equipment malfunction (circuit break-trip of a motorcontrol center) caused a complete loss of all feedwater heating due tototal loss of extraction steam. Accordingly, either (1) submit a suf-ficiently detailed failure modes and effects analysis (FMEA) to demonstratethe adequacy of a 100 F feedwater temperature reduction relative to singleelectrical 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 morerealistic slow changes with time. Assuming all combinations result in slowtransients with the surface heat flux in equilibrium with the neutron fluxat the occurrence of scram, a smaller temperature drop than 100 F thatstill causes scram could result in a larger QCPR. Please evaluate thistransient and justify that the assumed values of the magnitude and timerate of change in the feedwater temoerature are conservative.

RESPONSE:

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

The GE feedwater heater system design specification requires that the maximumtemperature decrease which can be caused by bypassing feedwater heater(s)by a simple valve operation will be less than or equal to 100oF. This isthe 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 insignificantly less than a 100 F temperature drop.

It should be pointed out that a steady state (i.e., the surface heat fluxin equilibrium with the neutron flux) is assumed in determining the MCPRduring the transient. Therefore, a temperature loss smaller than 100 F isnot 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 thatcredit is taken for nonsafety-grade equipment to terminate this event.Section 15.3.3 of the Standard Review Plan, Revision 1, rewuires use ofonly safety-grade equipment and the safety functions be accomplishedassuming the worst single failure of an active component. Reevaluatethis accidentwith the above specific criteria, and provide the resultingCPR and percentage of fuel rods in boiling transition.

RESPONSE:

The recirculation pump seizure enent, assuming the operation of specificnon-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/orradiological consequences of this highly improbable pump seizure (rapidcore flow decrease) event more limiting than the maximum DBA-LOCA addressedin the FSAR. Therefore, no additional evaluations are considered necessary.The FSAR text has been revised regarding frequency classification bydeleting references to infrequent incident classification in Subsection 15.3.3.1.2and 15.3 '.1.2, recirculation pump seizure and recirculation pump shaftbreak respectively

Rev. 22, 4/81 211.120-1

SSES-FSAR

Operation of Susquehanna with partial feedwater heating mightoccur during maintenance or as a result of a decision to operatewith lower feedwater temperature near end of cycle. Justify thatthis mode of operation will not result in (1) greater maximumreactor vessel pressures than those obtained with the assumptionused in Section 5.2.2, or (2) a more limiting 5MCPR than wouldbe obtained with the assumptions used in Section 15.0. The basisfor the maximum reduction in feedwater heating considered in theresponse should be provided (e.g., specific turbine operationallimitations).

RESPONSE:

Lower feedwater temperature increases the core inlet subcoolingand results in a corresponding decrease in both the core averagevoid fraction and the steam production. The feedwatertemperature of 250oF is considered as the lower limit based onthe conclusion that plants with improved interference fitspargers can be run in this mode (250 F FFVZ) without adverseconsequences. Typically, the core average void fraction isreduced by -16$ when the feedwater temperature is reduced from420 F to 250 F. The lower steam production rate reduces the peakpressures which occur during a transient (Table 211.125).

The use of feedwater temperature reduction to extend the cyclebeyond normal EOC is not expected to result in more severetransients. The lower void fraction ( "16$ lower at 250 F FFWT)reduces the dynamic void coefficient and the severity of thetransient (i.e., the ACPR due to the transient) is less. Table211.125 provides the typical ACPR numbers for two transientsanalyzed. Although the scram reactivity response is somewhatdegraded due to the less bottom peaked power shape, the overallresponse is dominated by the void feedback effects and theresulting transient is less severe. Reducing the feedwatertemperature before EOC will not result in more severe planttransient either. The peak pressures will be less due to thereduced steam production. The ACPR will be less due to thesmaller void coefficient. Due to the presence of a significantnumber of control rods inserted into the core for this condition,the scram response is not appreciably affected by the feedwatertemperature reduction. In addition, the transient response atpoints 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 modeof operation will not violate MCPR safety limits, given the eventsin Chapter 15.

Rev. 22, 4/81 211.125-1

TABLE 211. 125

TRANSIENT ANALYSIS RESULTS

Reactor~Cele Transient

ExposurePoint

PeakVessel

Pressure CPR

BWR4251"764Evil.cycle

Load rejectionw/o bypass

Rated EOC(104.2/ power)

1235 .17

(Reduced Feedwater) Extended EOCHeating (100$ power)

1219 0.16

FeedwaterControllerfailure

Rated EOC

(104.2$ power)1202 0.12

(Reduced'eedwater) Extended EOCHeating (100$ power)

1060 0.05

* ODYN ANALYSIS RESULTS

Rev. 22, 4/81

SSES-FSAR

In the evaluation of the "generator load rejection" transient, afull-stroke closure time of 0.15 seconds is assumed for theturbine control valves (TCV). Section 15.2.2.3.4 states that theassumed closure time is conservative compared to an actualclosure time of more like 0.20 seconds. However, in Figure 10.2-2, Turbine Control Valve Fast Closure Characteristic, anacceptable TCV closure time of 0.08 seconds is implied. Explainthis apparent non-conservative discrepancy and the effect it hason analyses in Chapter 15 requiring TCV closure.

RESPONSE:

The 0.08 seconds shown in Figure 10.2.2 is an acceptable valuewhereas the .07 seconds TCV closure time in Tables 15.2-1 and15.2-2 is the bounding value.

See response to Question 211.117 for further clarification tothis question.

Rev. 22, 4/81 211.161-1

SSES-FSAR

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

a) Table 15.4-6 indicates a low level alarm 10.5 seconds after pumpstart while Figure 15.4-6 indicates this alarm occurs about 11.5seconds 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 suchindication.

Resolve these discrepancies.

RESPONSE:

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

a) Table 15.4-4 indicates L4 near ll seconds. This is verified byFigure 15.4-6,

b) Table 15.4-4 indicates that vessel level is beginning to stabilizeat 50 seconds. This appears to be correct. Actually, levelrecovered from L3 at about 41 seconds and from 30 to 40 secondslevel is changing at the rate of 2.5 in/sec. From 50 to 60 secondslevel rate is definitely flattening out under normal feedwaterlevel control.

Rev. 22 4/81 211.180-1

SSES-FSAR

QUESTION 211.210:

Expand the discussion in Section 6.3 to describe the designprovisions that are incorporated to facilitate maintenance(includinq draininq and flushing) and continuous operation of theECCS pumps, seals, valves, heat exchangers, and piping runs inthe long-term LOCA mode of operation considering that the waterbeing recirculated is potentially very radioactive.RESPONSE:

The Susquehanna eguipment for long-term coolinq fcllowing apostulated LOCA includes two ccmplete coze spray systems and twoRHR systems. These tvo systems consist of a total of eight pumpscapable of pzovidinq water to the reactor pressure vessel. Thepipinq and instrumentation diagrams of these systems are shown inFigures 6.3-4 and 5.4-13. Lonq-term cooling vater can beprovided to the core by one RHR (LPCX mode) pump or one CS loop(both pumps), while heat can be rejected to the ultimate heatsink via either of the two RHR heat exchangers using one of fourRHR pumps. Thus a maximum of three pumps vould be required forpost-LOCA core coolinq. All of these components are desiqned toremain operable during and follovinq a Loss of Coolant Accident,and the redundancy provided is such that maintenance is notexpected to be required during the long-tera core cooling periodfollowinq a LOCA. Hovever, the RHR and Core Spray systems aredesigned with provisions for flushing as shovn in Figures 6.3-4a nd 5. 4-13.

Rev. 22 4/81 211 210-1

SSES-FSAR

gDESTXON 211.211:

Severe water hammer occurrence in the ECCS discharge pipingduring startup of the ECCS pumps is avoided by ensuring that thedischarge pipes are maintained full of water. The condensatetransfer system i used to achieve this function for all ECCSpiping. Since the condensate transfer system also supplies ~aterto numerous other systems, the following areas requireclarification: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 transfersystem and what effects, if any, would be expected on themakeup required to keep the discharge pipes full of water?

c) Can individual "filllines" be isolated to permitmaintenance on one ECCS system without affecting the othersystem?

d) The discharge piping "fillsystem" is apparently consideredto be an auxiliary system. Are any priority interlocksprovided to ensure that the "filling system" will be givenpriority over the other uses of the condensate transfersystem water?

e) The individual fill lines apparently do not haveinstrumentation to monitor low pressure. provide assurancethat when the condensate transfer pumps are operating thatthe individual ECCS discharge lines are full of water.

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

RESPONSE

a) The pump fillsystem adopted for Susquehanna SES utilizes the existingcondensate system and is relatively simple. Zt is believed to have ahigher system overall reliability than a system requiring individual pumps,or so-called jockey pumps, to perform the fillfunction. However, thereis no known operating experience with a common discharge line fillsystem.

The condensate transfer system has been designed to bereliable insomuch as it is required for plant operation.Therefore complete failure of this common filling system forthe ECCS would require that the plant be brought to ashutdown condition.

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

Rev. 22, 4/Sl 211.211-1

SSES-PSAR

.) The individual fill lines can be isolated to permitmaintenance on ECCS systems and individual loops'f a systemwithout affecting the other loops. See revised Subsection6.3. 2 2. 5.

d) Due to the very small amount of continuous make-up requiredno interlocks are provided to give priority to "keep-full"function of the Condensate Transfer System's ECCS filllines.

e) See revised subsection 6.3. 2.2.5.

f) The water hammer events which have occurred in BHR plantswith ECCS fillsystems are documented and transmitted to theNRC as Licensing Event Reports (LER) . These are kept onfile at the NRC. See Table 211.211-1 for a tabulation ofwater hammer events based on LER information on file withthe General Electric Company.

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 mostsevere operating conditions that are anticipated. The servicelife and the maximum expected operating time accumulated duringthe service life of that HPCI pump should be specified.

RESPONSE:

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

While they have never been called upon to function during a DBA,these pumps are periodically tested in operating plants and havebeen shown to perform satisfactorily.Each pump is tested at the vendor's plant for hydraulicperformance and freedom from vibration. This is in addition tothe tests and inspections performed during the fabrication of thepumps

The severe operating conditions to which the pumps are exposedare temperatures to 148 F ambient, maximum expected post-DBAradiation levels and dynamic loads due to the safe shutdownearthquake and hydrodynamic effects associated with the DBA. Thepumps are mainly fabricated of metallic materials which will notbe degraded by the expected post-DBA temperature and radiationenvironment. The non-metallic gaskets and seals are made ofmaterials with a demonstrated resistance to the post-DBAenvironment. The dynamic load inputs are addressed analyticallyand evaluated against appropriate criteria to assure operation ofthe pump while undergoing dynamic loading.

The above assures that the expected service life will exceed theexpected operating time of approximately 550 hours.

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

Event 0 eratin Time (Hours)

Shop TestingPreoperational TestingMonthly TestingYearly TestingPost-LOCAShutdown

21040

48012

N/A

The assumed operating time for post-LOCA is 12 hours for the HPCIpump. The low pressure RHR and CS systems take up the'core

Rev. 22'/81 211.226-1

SSES"FSAR

cooling within 12 hours after incipient LOCA event and maintainthe long term core cooling of post LOCA subsequent to 12 hoursperiod.

G E stated that the ECCS pump motors meet the environmentalq ualification requirements of the DOR guidelines and IEEE 323-1971.Prior to June 30, 1982, further qualification work will be preformedto bring these items up to at least the level of IEEE 323-1971per 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 thecontrol rod drive system which you state is provided in Appendix15A.

RESPONSE:

Subsection 4.6.2 has been revised to state that The Nuclear Safety andOperational 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 coastdownof the undamaged pump. Reanalyze this transient assuming coincident lossof offsite power and incorporate this reanalysis with that previouslyrequested in Q211.120.

RESPONSE:

The event severity of a coincident loss of offsite power with the postulatedrecirculation pump seizure accident is bounded by the analysis of "Loss of ACPower" as shown in Section 15.2.6. The only difference between these twoevents is the core flow coastdown rate, The flow coastdown rate during thepump seizure event coincident with a loss of offsite power is faster thanthat during the loss of AC power transient. The loss of AC power causes thisevent to become a pressurization event. The faster flow coastdown forpressurization events are less severe because of negative void reactivitycoefficient. If the loss of offsite power were coincident with the highwater level turbine trip, the resulting accident would be less severe thanthe one analyzed in the FSAR. This is due to the fact that the recirculationpump trip will occur earlier in the former accident.

To discuss the effect of core coastdown rate on CPR, the following ispresented. Core coastdown rate has an effect on the change in CPR. Thiseffect has two critical components which vary inversely with each other.The inverse relationship exists between the heat generation rate (neutronflux) and the heat dissipation rate (thermal hydraulics), The faster thecoastdown rate, the faster the neutron flux drops, but, the slower theresidual heat in the fuel is dissipated.

The events in Chapter 15 'are analyzed to conservatively account for thisrelationship with regards to the change in CPR-

Rev. 22, 4/81211.262-1

SSES-FSARg,»6:From the discussion of single failures for the "inadvertent HPCI startup"transient, it is indicated that a single failure of the pressure regulatoror level control will aggravate the transient, resulting in reduced thermalmargins. Provide the HCPR and peak vessel pressure values that result forthis event with the most limiting of the above single failures consideredin the analysis.

RESPONSE:

In the event of the "inadvertent HPCI startup" transient, neither thepressure regulator nor the level controller is expected to fail becauseboth systems are in normal continuous operation at the time of thehypothesized event, and no significant change in their function is demandedby the event. They should simply continue their normal function.

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

Because of the addition of the cooler water in feedwater sparger, the levelcontrol system tends to reduce the feedwater flow to maintain the normalwater level. When an active failure of the level control system isconsidered, the water level would continue to rise. .This situation issimilar 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 systemssignificantly, 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 worsethermal 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 thatthese systems should be designed to withstand the failure of anysingle active or passive component without adversely affectitheir long-term cooling capabilities. ln this regard, we areconcerned that the suppression pool in boiling water reactors (BWR's)may be drained by leakage from isolation valves which may be renderedinaccessible by localized radioactive contamination following apostulated loss-of-coolant accident (LOCA). Accordingly, indicatethe design features in the Susquehanna facility which will containleakage from the first isolation valve in the ECCS lines takingwater (suction lines) from the suppression pool during the long-termcooling phase following a postulated LOCA.

RESPONSE:

The ECCS is designed to withstand the failure of any single active orpassive comoonent without adversely affecting the long-term coolingcapabilities. Any leakage from ECCS systems can be isolated andcontained. The design features in Susquehanna that assure thiscapability 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 believesthat the state-of-the-art has progressed such that effective LPMsystems can be installed in commercial LWRs. The rationale forthis is documented in draft Regulatory Guide 1.133 (Loose-PartDetection Program for the Primary System of Light-Water-Cooled-Reactors). Additional rationale clarifying the staff positionc'n also be found in a letter, Vassallo to J. E. Mecca (PugentSound 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 andoperational prior to startup of the reactor. Therefore, pleaseprovide the information requested in Q221.1.

RESPONSE:

The Susquehanna SES Loose Parts Monitoring System is discussed insubsections 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 shouldcommit to submit a report describing the computer program used forcore thermal-hydraulic analysis prior to issuance of an operatinglicense for Susquehanna. The report should provide the codedescription, the calculational methods and empirical correlations used,a sample application and code verification through comparison withexperimental 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 ElectricCompany 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 statethermal-hydraulic module in the GEBS/PANAC three-dimensional BWR coresimulator. The models and non-proprietary correlations are describedin 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 requestedassumptions used for amount of crud used in design calculationsand the sensitivity of CPR and core pressure drop to variations inthe amount of crud present. Merely stating that "a conservativeamount of crud is deposited on the fuel rods and fuel rod spacers"does not begin to answer this question. The question also askedfor 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 madeto account for crud deposition. For pressure drop considerations,the amount of crud assumed to be deposited on the fuel rods andfuel rod spacers is greater than is actually expected at any pointin the fuel lifetime. This crud deposition is reflected in adecreased flow area, increased friction factors, and increasedspacer loss coefficients, the effect of, which is. to increase thecore pressure drop by approximately .1.7 psi, an amount which islarge enough to be detected in monitoring of core pressure drop.It should be noted that assumptions made with respect to cruddeposition in core thermal hydraulic analyses are consistent withestablished water chemistry requirements. More detailed discussionof crud (service-induced variations) and its uncertainty is found inSection IIIof Reference 3.

Reference:

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

2. Green, S. J., B. W. LeTourneau, A. C. Peterson, "Thermal andHydraulic Effects of Crud Deposited on Electrically Heated RodBundles", 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 operationaldesign guidelines are exceeded for some operating conditions, Figure4.4-6 should be revised to show decay ratios as a function of rodposition, recirculation flow and power. Figure 4.4-6 as currentlypresented is not sufficiently detailed for use in inferringoperational boundaries.

RESPONSE:

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

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

The criterion used with respect to safety is that the calculated decayratio be less than 1.0 over the expected range of operation. Thishas been demonstrated for Susquehanna unit. Operational guideshave 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 referenceNEDO-10958-A for a discussion of the uncertainties and their bases.The staff evaluation of NEDO-10958 states "The estimated value ofthe uncertainties and the basis for the value depend on the specificdesign and equipment of each reactor and will be evaluated for eachreactor at the time Technical Specifications are issued." Informationto support the uncertainty values for Susquehanna must be submittedprior to issuance of a safety evaluation report for Susquehanna.

RESPONSE:

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

Additional information concerning the remaining uncertainties inTable 4.4-6 and the bases used in the derivation of those uncertaintiesis contained in the Licensing topical report "Process ComputerPerformance Evaluation Accuracy" (References 2, 3 and 4). As statedtherein, "the analysis was performed...for measurements systemstypical of (or conservative with respect to) the BWR4-6," and istherefore 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 AccuracyAmendment 1," General Electric Company, December 1974 (NEDO-20340-1).

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

Rev. 22, 4/81230.4-1

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. Theresults of three turbine trip tests performed at the Peach Bottom-2 have revealedthat 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 beenapproved. Accordingly, the applicant is required to reanalyze prior to criticalitythe following transients with ODYN: 1) generator load rejection/turbine trip,2) feedwater controller failure~aximum demand and 3) main steam isolation valveclosure with position switch scram failure. If another event should be morelimiting than those listed above, the other event should reanalyzed with ODYN.The reanalyses should include CPR calculation and demonstrate that the operatinglimit 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 9.5-1automatic smoke detectors be provided in the following areas and that theyalarm and annunciate in the control room. Fire detectors should, as aminimum, be selected and installed in accordance with NFPA 72E, "AutomaticFire Detectors".

Reactor Building

Fire Zone Area Elevation

l. 1-1G2. 1-2A3. 1-3A4. 1-3B5. 1-3C6. 1-4A7. 1-4B8. 1-4G9. 1-5A

10. 1-5B11. 1-5D

12. 1-5E13. 1-6A14. 1-6D15. 1-6E16. 1-6F17. 0-6G18. 1-7A19. 1-7B20. 0-8A

Sump pump roomAccess areaAccess areaAccess areaAccess areaContainment access areaPipe penetration roomMain steam pipingFuel pool pumps 6 heatexchangersValve access areaRMCU Pumps 8 heatexchangersPenetration room

'ccessAreaHSV equipment roomRecirculation fans areaSpent fuel poolSurge tank vaultHRV fan and filter roomsRecirculation fan roomRefueling floor

645-668670-683683-719683-719683-719719-747719-733717-816

749-771761-771

749-766749-777779-797779-797778-797779-797775-797779-816799-816818-873 partial

RESPONSE:

Each of the areas listed are being examined to determine if they contain orpresent a fire exposure hazard to safety-related systems necessary toaccomplish or maintain a safe-shutdown condition. Additional smokedetection will be provided in those areas satisfying either criteria. Thisis documented in Revision l 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 PPSLis identified in the emergency plan, as is the system used by theLuzerne County Office of Civil Defense and the PA Bureau ofRadiological Health. While these classification systems appearcompatible, the terms used are different and no direct comparisonis made in the plan. Provide such a comparison between theclassification terms used by PPM and those used by the offsiteagencies, either in the text of Section 4 of the plan, or onFigure 6.1.

RESPONSE

o As established in 10CFR50 Appendix E and NUREG 0654/FEMA REPl, Rev. l, PPSI,, State, and Local Emergency Plans haveincorporated the same emergency classification system. Theclassification system outlined in Section 4.0 of theSusquehanna SES Emergency Plan Rev. 2 dated October 1980 isidentical to the state and local emergency classificationsystem.

Rev. 22, 4/81 313.1-1

SSES-FSAR

UESTION 313.6

Concerning protective actions, describe steps taken to makeavailable on request to occupants in the low population zone,information concerning how the emergency plans provide fornotification to them and how they can expect to be advised whatto do.

RESPONSE

The following methods will be implemented to ensure informationon Emergency Planning is transmitted to the Emergency PlanningZone residents. Annually, a full page ad, summarizing theinstruction and action to be taken by the EPZ residents in theevent of an emergency will be published in the local newspaper.Annually, printed instructions and evacuation maps will bedistributed to residents within the EPZ.

Evacuation maps and printed instructions will be printed in alltelephone directories within the EPZ. An alert .warning sirensystem controlled by the county Emergency Operations Centers willbe installed within the EPZ to provide early notification to thepublic. This system will alert the public to tune to the localEmergency 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 ofthe Berwick Hospital to show that they are prepared and qualifiedto handle radiological emergencies.

RESPONSE

Key members of the Berwick Hospital Staff will be initiallytrained at the Oak Ridge "REACTS" course. Annual training ofappropriate Berwick Hospital personnel will be provided by aconsultant experienced in the handling of contaminated/irradiatedinjured personnel.

Annual drills of Berwick Hospital staff members will be conductedand critiqued to ensure their ability to handle radiologicalemergencies.

Rev. 22, 4/81 313.7-1

SSES"FSAR

UESTION 313.8

Provide a commitment to conduct annual exercises to test theadequacy 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 ofthe Emergency Plan will be changed to read: "An initial exerciseprior to loading of fuel for Unit 1 and annual exercisesthereafter will involve a scenario appropriate to a SiteEmergency or General Emergency Condition."

These exercises will be conducted using the guidelines of10CFR50 Appendix F NUREG 0654/FEMA REP 1 Rev. l, and ANSI/ANS-3.7.3-l979.

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 asaltered by the plant. Note that FSAR Figure 2.4-1 is inadequatebecause it is very difficult to see the contours in the vicinityof the plant.

RESPONSE:

Figure 2.5"24 has been revised and shows all the present roadsand 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 intendto "onduct confirmatory tests of some Distcibutio syst ms anitransformers suoplying pow r to vital buses as reguiceD byPosition 3 of Regulatory Guide 1.68, and more specificxtlly byPact 4 of the staff position on Degraded grid voltage (applied toall plants in li=ensing ceview by the Power Systems Branch sin"e1976) . Part 4 of the d gcaDeD gciD voltage position states asfoliows:

Tha voltage leveLs at the safety-related'uses shouldbe optimized for the full loaD and mininum loadconditions that ace expecteD thcoughout th anticipatedrange of voltage variations of the offsite power sourceby appropriate aD justment of the voltage tap settingsof the intervening tcansfocmecs. He require that theadequacy af the Design in this regard be verified byactual measurement and by correlation of measuredvalues with analysis results.„ Provide z Description ofthe method foc making this vacification; before initialreactor power opecation, pcovide the do"umentationrequiceD to establish that this vecification has beenaccomplished.'!

Your test description in FSAR .Chap.tec l4 does not containsufficient detail for us t> determine if you intend to conductsuch a test. It is our position that ™onficmxtory tests of allvital buses must be conducted including all sour"es of powecsupplies to the buses Noiify your test Description to indicatethat this testing will be conducted in accordance with RegulatoryGuide 1 68 and the above citeD position..BZSPOBSZ=.

Voltages recorded during the P100.1 Preoperational test (Subsection14.2.12.1), will be reviewed and analyzed against design calcul'ationsto assure optimal tap settings have been selected.

Rev. 22, 4/81 421.042-1

SSES-FSAR

5o us5

5. x.

5. z.

5. c.c

5.f.f

5 h.h

valves: and turbine stop, inte cept, and controlval ves.Verify response times of branch steam line isolation.Demonstrate adequate performance margins for shieldingand penetration cooling systems capable of maintainingtern peratures of cooled components within design limitswith the minimum design capability of cooling systemcomponents available (100/)Demonstrate adequate beginning-of-I.ife performancemargins for auxiliary systems required to supportthe operation of enqineered safety features orto maintain the environment in spaces that houseenqineered safety features. Engineered safetyfeatures will be capable o performing theirdesign functions over the range of designcaoability of operable components in theseauxiliary systems (50%, 100%) .Demonstrate that process and effluent radiationmonitoring systems are responding correctly.

Demonstrate that gaseous and liquid radioactivewaste processinq, storage, and release systemsoperate in accordance with design.Demonstrate that the ventilation system that servesthe main steam line tunnel maintains temperaturewithin the design limits.Demonstrate that the dynamic response of the plantto the desiqn load swings for the facility.

5o isla

5.1.1.

Demonstrate that the dynamic response of the plantis in accordance with design for closure oX reactorcoolant system flow control valves.Demonstrate that the dynamic response of the plantis in accordance with design requirements for turbinetrip.

QESPOQS~

Preoperational tests of safety related systems are described bythe test abstracts provided in subsection 14-2-12-1. Specificdetailed 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 withinthe system such as switching automatically to a different powersource. Loss of air testing is performed by placing the valve inits non-failed position by normal actuator operation, then isolatingthe actuator air supply, blet ding off air pressure and verifyingvalve movement to the failed position. Each automatic containmentisolation valve is tested in the system pre-op test. for proper oper-ation and closure timing as required by the design sections of theFSAR. Leak detection systems such as steam leak detection aretested 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 inRegulatory Guide 1.80 sections C.7 through C.10 will not be donesince the testing will have already been done during "varioussystem preoperational tests". Either provide test descriptionsthat show testing equivalent to that specified in regulatorypositions C.8, C.9, and C.10 will be performed, or modify yourpreoperational test program to include an integrated loss of airtest 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 aretested for loss of air. Preoperational tests within which theloss of air testing is accomplished is also provided inTable 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 accumulatorpressure of 75+0-2 PSIG and fails closed on loss of air.

Rev. 22, 4/81 423.28-1

SYSTEM

RHR

VALVE NO.

1-Ell«P050A;BPREOP. NO.

P49.1

INST. AIR OR PRI.CONT. INST. GAS

~Inst< Air

C

CO

1-E11-P122A,B

'-E11-F051A,B

1-Ell«F052A,B

1-E11-P053A,B

l-E11-F305A,D

Inst; Gas

Inst. Air

1-'Ell-PlllA,B

1«Ell-F129A,B .

l-E11-F132A,B

1«E11-F136,F137,P140

HV-E51-'17088 ' '..'V-E51-1F025;1P026

W-E51-1F004,1F005

'HV-E51-1P054

~ Core Spray . HV-E21 lF006A,B

~ 1N-E21~1F037A, B ~ ~

P50;1'

$51.1

'Inst'Gas'nst;

Air .

':ln'st; 'Gas

HPCI

CRD..-

HV-E41-.1F028,1F029

HV»E41-1F025,1P026

'HV-E41-1P057,1P100.

C12-POoaA,B.......

XV-lP010, 1P011

. HV-B31-1P019;1P020 .Both + '

~ ~ ~

'52;1' ' '

~

~ ~

~ P55sl

~ ~ \ ~

Inst; Air

' '1F100'Ga's'

Inst. Air0the s.Ins't'ir

~ ~ ~

SYS VALVE NO. PREOP NO.INST. AIR OR PRICONT. INST. GAS

Pire Protection XV-12244,45;46,48,49

XV-12205A,B, C

XV-02247A,B;C

XV-02248.

XV-02215

liv-11315

'P13

P14

.Inst; 'Air

'Inst;.Air'B

HVAC llD17534A,B,C,D,E,ll',ll All+'ID17502AjB;Hg17514A,B All *

1 ~ P34;X Inst;'A'ir

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..

SYSTEM VALVE NO. PREOP. NO.INST. AIR OR PRI.CONT. INST. GAS

RWCU ia" " 'ii )o

HV-14506A;B; 14507A,B.

HV-14508A,B; 14510A,B

. P61'.3.'nst; Air

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

16108A2, 16116AL Both '*

~ ~

e

~ /

P69'.1'Ihst; 'Air'

Containment

Recirculation

HV-17521,23,24,22,25'A11''

HV-15704 0514'All'''V-15703;13..

~ ~ 'P73'.1' Inst.'Aii'

~ ~ ~

/ ~ ~ ~ ~

'0

~ ~

/~ ~ —

SYSTEM VALVE NO. PREOP. NO.INST- AIR OR PR

CONT. INST. GAS

R.B. HVAC PDD 17501A;B; HD17511A;9 '34'.'1'nst; 'Air

RB Chilled Mater

HD17521A B; HD17513A 9

HD17518A,B; HD17516

HD17523A,B; HD17528A,B

PDD17578A,B; HD17526 ':HD17566A~ B~ )'ID17588Af'9

HD17538A,B

TV-18726A1,A2,B1,92

TV-18741A; 9, C, D

TV«18743A, B

.P34.2.

~ ~

Inst; Air

TV-18751A 9 C D

~ TV-18753A,B

TV-18764A,B

TY-18771A;9;C,D

~ TV-18781A1 A2,91 92,A11 +

HV 18782A1 ~A2 ~ 91 ~92~A11

HV-18791A1, .A2,91, 92h11 *

\ ~

Inst;.Gas.

HV-18791AlgA2,91; 92All .* ~ ~

SYSTEM VALVE NO. PREOP. NO.INST. AIR OR PRI.CONT. INST. GAS

Control Structure

QHVAG

HDM&7802A B 'oth *

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

0 O.l

P30..2. ~ .'....Feedwater 10604A B C

'10640 '106'41

14107A,B 10650

'10606A,B;C 10604A,B;C '

0 6 6 3A'1~ A2 ~ B1 ~ B2 7 C1 ~ C2

10664A;B,C .

~ ~ ~ ~ ~

~ ~

SSES-FSAR

Our review of recent licensee event reports disclosed that asignificant number of reported events concerned the operabilityof hydraulic and mechanical snubbers. Provide a descriptionof the inspections or tests that will be performed followingsystem operation to assure that the snubbers are operable. Theseinspections or tests should be performed preoperationally ifsystem operation can be accomplished prior to generation ofnuclear heat.

RESPONSE:

Existing QA records on the construction installation and inspectionof safety related snubbers will be assembled into a package forreview by the Superintendent of Plant. This package will provideassurance that the preoperational condition of the snubbers isacceptable and that they are installed in accordance with design.

After system preoperational testing and prior to fuel load, snubberswill be visually examined and manually tested fcr freedom ofmovement over the range of stroke in both compression and tension.This meets the requirement of ZE Bulletin 81-01 Rev. 1. Nohydraulic'nubbers are utilized in safety applications atSusquehanna SES.

Rev. 22, 4/81 423.40-1